Federal Register of Legislation - Australian Government

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SLI 2014 No. 5 Regulations as made
This regulation amends the Offshore Petroleum and Greenhouse Gas Storage (Environment) Regulations 2009 and the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Regulations 2004 to facilitate streamlining of environmental approvals for offshore petroleum and greenhouse gas activities under the OPGGS Act and the Environment Protection and Biodiversity Conservation Act 1999, and implement the findings of a review of the Principal Regulations.
Administered by: Industry
Registered 19 Feb 2014
Tabling HistoryDate
Tabled HR24-Feb-2014
Tabled Senate03-Mar-2014
Date of repeal 02 Oct 2014
Repealed by Division 1 of Part 5A of the Legislative Instruments Act 2003

EXPLANATORY STATEMENT

 

Select Legislative Instrument No. 5, 2014

 

Issued by the authority of the Minister for Industry

 

Offshore Petroleum and Greenhouse Gas Storage Act 2006

 

Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Act 2003

 

Offshore Petroleum and Greenhouse Gas Storage Legislation Amendment (Environment Measures) Regulation 2014

 

The Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGGS Act) provides the legal framework for the exploration for and recovery of petroleum, and for the injection and storage of greenhouse gas substances, in offshore areas. 

 

Section 781 of the OPGGS Act provides that the Governor-General may make regulations prescribing matters required or permitted by the Act to be prescribed, or necessary or convenient to be prescribed for carrying out or giving effect to the OPGGS Act.

 

The Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Act 2003 (Regulatory Levies Act) imposes environment plan levies on submission of environment plans or revisions of environment plans under the Offshore Petroleum and Greenhouse Gas Storage (Environment) Regulations 2009 (the Principal Regulations). Environment plan levies are collected by the regulator of environmental management for the offshore petroleum industry, the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA). Amounts of levy collected are credited to the National Offshore Petroleum Safety and Environmental Management Authority Special Account under section 683 of the OPGGS Act and are used to fund NOPSEMA’s operations on a cost-recovery basis.

 

Section 11 of the Regulatory Levies Act provides that the Governor-General may make regulations for the purposes of a number of sections of the Regulatory Levies Act, including sections 10F and 10G, which impose environment plan levies in relation to activities authorised by Commonwealth titles and State/Northern Territory titles respectively. 

 

The Principal Regulations provide for the regulation of environmental management of upstream petroleum and greenhouse gas activities in offshore areas. The object of the Principal Regulations is to ensure offshore petroleum and greenhouse gas activities are carried out in a manner that is consistent with the principles of ecologically sustainable development, and in accordance with an environment plan that has appropriate environmental performance objectives and standards, and measurement criteria for determining whether the objectives and standards have been met.

 

Under the Principal Regulations, persons who want to conduct a petroleum or greenhouse gas activity are required to prepare and implement an environment plan for the period of the activity. The Regulator (NOPSEMA in relation to petroleum activities; the responsible Commonwealth Minister in relation to greenhouse gas activities) must assess the environment plan and decide whether to accept it. The required content of an environment plan, and the acceptance criteria that the Regulator must apply in deciding whether to accept an environment plan, are detailed within the Principal Regulations.

 

The Offshore Petroleum and Greenhouse Gas Storage Legislation Amendment (Environment Measures) Regulation 2014 (the Regulation) amends the Principal Regulations to:

·         Facilitate streamlining of environmental approvals for offshore petroleum and greenhouse gas activities under the OPGGS Act and the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act); and

·         Implement the findings of a review of the Principal Regulations.

 

Facilitating streamlining of environmental approvals

In 2013, the Australian Government made an election commitment to streamline environmental management regulation for offshore petroleum and greenhouse gas activities by making NOPSEMA the sole designated assessor for offshore environmental management of petroleum activities undertaken in its jurisdiction. Streamlining regulatory processes for environmental management of these activities will provide greater certainty for business, accelerate approval times and support investment decisions, and promote Australia as an attractive investment destination while maintaining strong environmental safeguards.

 

On 25 October 2013, the Minister for Industry, the Minister for the Environment and the Chief Executive Officer of NOPSEMA agreed to undertake a Strategic Assessment under Part 10 of the EPBC Act of NOPSEMA’s offshore petroleum and greenhouse gas environmental management authorisation process. This authorisation process is described in a key document, ‘the Program’, which constitutes the ‘plan, policy or program’ under section 146 of the EPBC Act and describes the regulatory processes under the Principal Regulations, as amended by the Regulation.

 

The Strategic Assessment was undertaken to allow the Minister for the Environment to endorse the Program under the EPBC Act and approve actions or classes of actions undertaken in accordance with the Program.

 

The key amendments to the Principal Regulations to facilitate streamlining include:

·           Introduction of a new environmental assessment process, the ‘offshore project proposal’, to capture large-scale petroleum developments that are likely to have a significant impact on matters protected under Part 3 of the EPBC Act, and provide for a mandatory public consultation process for those developments. A fee is payable for consideration of an offshore project proposal by NOPSEMA, as a fully cost-recovered agency;

·           Introduction of an acceptance criterion for environment plans whereby the Regulator cannot accept an environment plan for an activity or part of an activity being undertaken in any part of a declared World Heritage property;

·           Inclusion of a specific reference to certain matters protected under Part 3 of the EPBC Act in relation to the requirement to describe the environment that may be affected by an activity in an offshore project proposal and environment plan.

 

NOPSEMA’s functions under the OPGGS Act and regulations are fully cost-recovered through industry levies and fees. As there is no other levy or fee payable that would recover NOPSEMA’s costs of administering the new regulations regarding offshore project proposals, the Regulation provides for a fee to be paid to NOPSEMA for its consideration of a proposal. (Under subsection 685(1) of the OPGGS Act, the regulations may provide for the payment to NOPSEMA, on behalf of the Commonwealth, of fees in respect of matters in relation to which expenses are incurred by NOPSEMA under the OPGGS Act or regulations.) The total amount of the fee would not exceed the total of the expenses incurred by NOPSEMA in considering the proposal.

 

Implementing the review findings

The Australian Government began a review of the Principal Regulations in 2012 to assess the efficiency and effectiveness of their operation. The Regulation implements the outcomes of the review, including:

·           Strengthening the object of the Principal Regulations to include specific reference to the core concepts of ensuring environmental impacts and risks will be reduced to as low as reasonably practicable and of an acceptable level;

·           Amendment of the definition of ‘petroleum activity’, to clarify and narrow the scope of the definition;

·           Transfer of responsibility for submission of and compliance with an environment plan, and for compliance with the Principal Regulations generally, from the operator of an activity to the titleholder;

·           Clarification of the process for assessment of an environment plan. This would include amendments to the process for modification and resubmission of an environment plan, in the event that the Regulator is not reasonably satisfied that the plan meets the acceptance criteria;

·           Inclusion of a specific ability for the Regulator to request additional information before making a decision in relation to a submitted environment plan;

·           Introduction of a requirement for the Regulator to publish a notification of a proposed activity on its website on submission of an environment plan by a titleholder;

·           Extension of the content requirements for an environment plan summary to include a summary of arrangements for monitoring and oil pollution emergency response;

·           Renaming the ‘oil spill contingency plan’ to ‘oil pollution emergency plan’ and clarification of the required content of a plan;

·           Clarification of the requirement for an environment plan to provide for monitoring arrangements for both normal operations and emergency conditions, including monitoring to inform response and remediation activities;

·           Clarification of incident reporting requirements, including provision for the Regulator to request additional written reports of reportable incidents;

·           Insertion of a new regulation which would provide a standalone requirement for titleholders to submit reports to the Regulator about their environment performance no less than annually;

·           Insertion of a new regulation to enable titleholders to reference information previously provided to the Regulator, rather than resubmit the information;

·           Other minor or technical amendments to clarify requirements under the Principal Regulations.

 

The Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Regulations 2004 (Regulatory Levies Regulations) prescribe matters necessary to enable the full and effective collection of environment plan levies imposed on titleholders by the Regulatory Levies Act, including prescription of how levies are calculated.

 

The Regulation also amends the Regulatory Levies Regulations to require NOPSEMA to refund the compliance-related component of an environment plan levy that has already been paid, and remit compliance-related amounts that have not yet been paid, if a titleholder withdraws an environment plan it has submitted under regulation 9 before a decision is made to accept or refuse to accept the plan.

 

Details of the Regulation are set out in Attachment 1. The Regulation is a legislative instrument for the purposes of the Legislative Instruments Act 2003.

 

The amendments in Schedule 1 to the Regulation, which facilitate streamlining of environmental approvals and implement the outcomes of the review, commence on 28 February 2014. The amendment in Schedule 2 to the Regulation, which reflects an amendment to the OPGGS Act to enable NOPSEMA to appoint ‘NOPSEMA inspectors’, rather than ‘petroleum project inspectors’, will commence at the same time as Schedule 1 to the Offshore Petroleum and Greenhouse Gas Storage Amendment (Compliance Measures) Act 2013 (Compliance Measures Act).

 

The Regulation is compatible with the human rights and freedoms recognised or declared under section 3 of the Human Rights (Parliamentary Scrutiny) Act 2011. A full Statement of Compatibility is set out in Attachment 2.

 

The Office of Best Practice Regulation (OBPR) was consulted in the preparation of the Regulation. OBPR advised that no regulatory impact analysis was required to be undertaken in relation to the amendments to implement the review of the Principal Regulations.

 

In relation to the amendments to facilitate streamlining of environmental approvals, a Regulatory Impact Statement (RIS) was prepared and approved in accordance with the OBPR Handbook (July 2013). A copy of the RIS is at Attachment 3.

 

Consultation

The 2012 review of the Principal Regulations was undertaken with the assistance of a reference group of key stakeholders, including NOPSEMA, relevant State and Territory authorities and industry stakeholders. This process culminated in the development of an issues paper which was released for a two month public comment period in December 2012. Stakeholder views and general feedback received as part of the review process were considered in the development of the Regulation.

 

The Terms of Reference for the Strategic Assessment was finalised and agreed following four weeks public consultation. In September 2013, Departmental officials conducted targeted face-to-face stakeholder consultation with industry, fishing and environmental non-governmental organisations (NGOs), as well as relevant government departments. The Department established an Offshore Environmental Streamlining Taskforce (the Taskforce) consisting of officers from the Departments of Industry and Environment, NOPSEMA, and technical support from industry and academia, to undertake the Strategic Assessment and progress amendments to the Principal Regulations.

 

On 22 November 2013, the draft ‘Program’ report and draft Strategic Assessment Report were released for public consultation. The public comment period was advertised in national newspapers on Saturday 23 November 2013, and submissions closed on 20 December 2013. On 6 December 2013, an Exposure Draft of amendments to the Principal Regulations was released for public consultation. Comments on the Exposure Draft also closed on 20 December 2013.

 

The Taskforce held 13 information sessions on the strategic assessment documents and the Exposure Draft amendment regulations, in Hobart, Melbourne, Adelaide, Perth and Canberra during the weeks of 25-29 November and 9-12 December 2013. A total of 308 individuals representing industry, NGOs, the fishing industry and government attended. Invitations for these sessions and regular updates were sent to stakeholders through the Taskforce stakeholder list (approximately 350 subscribers), Australian Petroleum News (approximately 1200 subscribers), and NOPSEMA’s stakeholder information alert system (approximately 880 subscribers). Notices were also published on the Department of Industry, the Department of the Environment, and NOPSEMA websites.

 

The Taskforce received 38 written submissions on the Strategic Assessment, 32 of which also commented on the draft Regulation. Further information is provided in Appendix B of the RIS attached to this Explanatory Statement.

 


Details of the Offshore Petroleum and Greenhouse Gas Storage Legislation Amendment (Environment Measures) Regulation 2014

 

Section 1 – Name of regulation

 

This section provides that the title of the Regulation is the Offshore Petroleum and Greenhouse Gas Storage Legislation Amendment (Environment Measures) Regulation 2014.

 

Section 2 – Commencement

 

This section provides for sections 1 to 4 of, and Schedule 1 to, the Regulation to commence on 28 February 2014. This commencement date is required for the streamlining of offshore petroleum and greenhouse gas environmental approvals.

 

Schedule 2 to the Regulation will commence at the same time as Schedule 1 to the Offshore Petroleum and Greenhouse Gas Storage Amendment (Compliance Measures) Act 2013 (Compliance Measures Act). Schedule 2 replaces references to a ‘petroleum project inspector’ with references to a ‘NOPSEMA inspector’, to reflect a change in name that will be made in the OPGGS Act on commencement of the amendments in Schedule 1 to the Compliance Measures Act – see item 1 of Schedule 2.

 

Section 3 – Authority

 

This section provides that the Regulation is made under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGGS Act) and the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Act 2003 (Regulatory Levies Act).

 

Section 4 – Schedule(s)

 

This section provides that existing named instruments are amended or repealed as per the terms of the Schedules contained in the Regulation. Any other item in a Schedule has effect according to its terms.

 

Schedule 1 – Amendments commencing 28 February 2014

 

Offshore Petroleum and Greenhouse Gas Storage (Environment) Regulations 2009

 

Item [1] – Regulation 3

 

The Principal Regulations define and refer to a ‘greenhouse gas activity’. This item removes the word ‘storage’ in regulation 3 to ensure this regulation also refers to ‘greenhouse gas activity’, rather than ‘greenhouse gas storage activity’.

 

Item [2] – Paragraphs 3(a) and (b)

 

Regulation 3 of the Principal Regulations sets out the object of the Regulations. This item makes several amendments to regulation 3.

 

First, this item amends regulation 3 to define ‘principles of ecologically sustainable development’ by reference to section 3A of the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act). Although the term ‘principles of ecologically sustainable development’ is currently used in the Principal Regulations, a definition is not provided.  

 

Secondly, this item amends regulation 3 to provide that the object of the Regulations includes ensuring that any petroleum or greenhouse gas activity carried out in an offshore area is:

·         Carried out in a manner by which the environmental impacts and risks of the activity will be reduced to as low as reasonably practicable; and

·         Carried out in a manner by which the environmental impacts and risks of the activity will be of an acceptable level.

 

These concepts are fundamental to the Principal Regulations and at the core of objective-based regulation of the environmental impacts of petroleum and greenhouse gas activities. Acceptance of an environment plan for an activity by the Regulator relies on a demonstration in the plan that the environmental impacts and risks of the activity will be reduced to as low as reasonably practicable, and be of an acceptable level. It is therefore appropriate that these concepts are included up-front as an object of the Regulations.

 

Thirdly, this item amends regulation 3 to remove references to environmental performance objectives and standards, and measurement criteria for determining whether the objectives and standards have been met, in the object of the Regulations. Having appropriate objectives, standards and measurement criteria in an environment plan are means of achieving the object of the Regulations, and are not objects in themselves.

 

Item [3] – Subregulation 4(1)

 

This item converts current subregulation 4(1) in the Principal Regulations into regulation 4, as subregulation 4(2) is to be deleted – see item 34.   

 

Item [4] – Subregulation 4(1) (definition of accepted)

 

This item repeals the definition of ‘accepted’ in the Principal Regulations. The Regulation includes an amendment to insert a new definition of ‘in force’, in relation to an environment plan (see item 20), and also changes references within the Regulations from an accepted environment plan to an environment plan in force. The definition of ‘accepted’ is therefore no longer required.

 

Item [5] – Subregulation 4(1)

 

This item inserts a definition of ‘accepted offshore project proposal’ in the Principal Regulations.

 

Item [6] – Subregulation 4(1)

 

This item inserts a definition of ‘control measure’ in the Principal Regulations. The definition has been inserted to support other amendments made by the Regulation to clarify the link between environmental performance standards and control measures – see also items 12 and 48.

 

Item [7] – Subregulation 4(1) (definition of environmental impact)

 

This item omits the reference to an ‘operator’ in the definition of ‘environmental impact’. The concept of an ‘operator’ has been removed from the Principal Regulations – see item 24.

 

Item [8] – Subregulation 4(1)

 

This item inserts a definition of ‘environmental management system’ in the Principal Regulations. This supports the reference to ‘environmental management system’ that has been included as a result of the amendment to subregulation 14(3) in item 49.

 

Item [9] – Subregulation 4(1) (definition of environmental performance)

 

This item in effect amends the current definition of ‘environmental performance’ in the Principal Regulations. The amendment removes the reference to an ‘operator’, as the concept of an ‘operator’ has been removed from the Principal Regulations – see item 24. The amendment also replaces the reference to ‘environmental performance objectives’ with a reference to ‘environmental performance outcomes’ – see items 10 and 11.

 

Item [10] – Subregulation 4(1) (definition of environmental performance objective)

 

This item repeals the definition of ‘environmental performance objective’ in the Principal Regulations. This definition was inserted into the Principal Regulations in 2005, with the intent of aligning the definition with international standards for environmental management systems. However, the former definition was insufficient in this regard and also lacked clarity, so that broad statements that were not specific to the particular activity or the attendant risks to the environment were commonly being included as environmental performance objectives in environment plans. 

 

The Regulation also inserts a new definition of ‘environmental performance outcome’ – see item 11. Amending the definition provides clarity for titleholders, in particular to ensure that it is clear that outcomes should be specific to the particular activity and environment in which the activity is to be undertaken. The new definition provides for outcomes to be set so that titleholders can demonstrate that their environmental performance will meet or better the acceptable level of impacts and risks for the activity. 

 

The word ‘objective’ has also been changed to ‘outcome’, as the former was relatively vague and suggested a desirable or aspirational level of performance rather than a firm outcome that a titleholder commits to achieve in practice. Changing the term ensures that titleholders are aware that they must set specific, measureable benchmarks for their environmental performance, that can be monitored and enable a determination as to whether those outcomes are being met.

 

Item [11] – Subregulation 4(1)

This item inserts a definition of ‘environmental performance outcome’ in the Principal Regulations – see discussion in relation to item 10.

 


 

Item [12] – Subregulation 4(1) (definition of environmental performance standard)

 

This item amends the definition of ‘environmental performance standard’ in the Principal Regulations.

 

The Regulation includes amendments that clarify the link between environmental performance standards and control measures – see item 48. The definition of ‘environmental performance standard’ has been amended to refer specifically to, and thereby emphasise the link to, control measures. A definition of ‘control measure’ has also been inserted into the Principal Regulations – see item 6.

 

Item [13] – Subregulation 4(1)

 

This item inserts a definition of ‘Environment Minister’ in the Principal Regulations.

 

Item [14] – Subregulation 4(1) (definition of environment plan)

 

This amends the definition of ‘environment plan’ in the Principal Regulations.

 

The Regulation includes an amendment that inserts a new definition of ‘in force’, in relation to an environment plan (see item 20), which overlaps in part with the current definition of ‘environment plan’. The new definition is consistent with the definition of ‘safety case’ in the Offshore Petroleum and Greenhouse Gas Storage (Safety) Regulations 2009 (Safety Regulations).

 

Item [15] – Subregulation 4(1)

 

This item inserts a definition of ‘EPBC Act’ in the Principal Regulations.

 

Item [16] – Subregulation 4(1) (definition of greenhouse gas activity)

 

This item amends the definition of ‘greenhouse gas activity’ in the Principal Regulations.

 

The review of the Regulations determined that an amendment to the definition of ‘petroleum activity’ was required, to clarify and narrow the potential scope of the definition. The Regulation therefore includes an amendment to the definition of ‘petroleum activity’ – see item 25. The amended definition of ‘greenhouse gas activity’ mirrors the amended definition of ‘petroleum activity’, and is also necessary to support the transition in responsibility for compliance with the Regulations from the operator to the titleholder – see item 24.

 

The discussion with respect to the amended definition of ‘petroleum activity’ in item 25 is also generally applicable in relation to the amended definition of ‘greenhouse gas activity’.

 

Item [17] – Subregulation 4(1) (definition of greenhouse gas instrument)

This item would repeal the definition of ‘greenhouse gas instrument’. The Principal Regulations currently refer to an ‘instrument’ and ‘instrument holder’, whereas the OPGGS Act and other regulations under that Act refer to a ‘title’ and ‘titleholder’. For consistency, the definition of ‘greenhouse gas instrument’ is therefore to be repealed and a definition of ‘greenhouse gas title’ would be inserted by item 19.

 

Item [18] – Subregulation 4(1) (definition of greenhouse gas instrument holder)

 

This item would repeal the definition of ‘greenhouse gas instrument holder’. The Principal Regulations currently refer to an ‘instrument’ and ‘instrument holder’, whereas the OPGGS Act and other regulations under that Act refer to a ‘title’ and ‘titleholder’. For consistency, the definition of ‘greenhouse gas instrument holder’ is therefore to be repealed and a definition of ‘greenhouse gas titleholder’ would be inserted by item 19.

 

Item [19] – Subregulation 4(1)

 

This item would insert definitions of ‘greenhouse gas title’ and ‘greenhouse gas titleholder’ in the Principal Regulations.

 

The Principal Regulations currently include definitions of ‘greenhouse gas instrument’ and ‘greenhouse gas instrument holder’, which would be repealed by items 17 and 18 – see discussion in relation to those items. The main difference between the current definitions and the new definitions is the inclusion of a greenhouse gas research consent as a greenhouse gas title and, consequently, a holder of a greenhouse gas research consent as a greenhouse gas titleholder. Activities such as a seismic survey, which may have an impact on the environment, may be undertaken under a greenhouse gas research consent. It is therefore appropriate that relevant activities undertaken under a greenhouse gas research consent require an environment plan to be developed, and accepted by the Regulator, prior to undertaking the activity. 

 

Item [20] – Subregulation 4(1)

 

This item would insert a definition of ‘in force’, in relation to an environment plan, in the Principal Regulations. A number of regulations currently refer to an environment plan in force for an activity; however a definition of ‘in force’ is not provided.

 

The new definition is based largely on the definition of ‘in force’, in relation to a safety case, in the Safety Regulations. The effect of the definition would be that an environment plan, including a revised environment plan, is in force when the plan has been accepted by the Regulator. The plan would cease to be in force if acceptance of the plan has been withdrawn by the Regulator under Division 2.5 of the Regulations, or if the operation of the plan has ended in accordance with regulation 25A (see item 73).

 

Item [21] – Subregulation 4(1) (definition of instrument holder)

 

This item repeals the definition of ‘instrument holder’. The Principal Regulations formerly referred to an ‘instrument holder’, whereas the OPGGS Act and other regulations under that Act refer to a ‘titleholder’. For consistency, the definition of ‘instrument holder’ has therefore been repealed and a definition of ‘titleholder’ has been inserted by item 33. Amendments have also been made to references to an ‘instrument holder’ throughout the Principal Regulations, replacing them with references to a ‘titleholder’.

 


 

Item [22] – Subregulation 4(1) (definition of nominated address)

 

This item repeals the definition of ‘nominated address’. The definition was previously included in relation to an operator; however the concept of an ‘operator’ has been removed from the Principal Regulations – see item 24.

 

Item [23] – Subregulation 4(1)

 

This item inserts definitions of ‘offshore project’ and ‘offshore project proposal’ in the Principal Regulations.

 

Offshore project

The definition of ‘offshore project’ refers to ‘activities’ undertaken for a particular purpose. An ‘activity’ includes a ‘petroleum activity’, which is defined in regulation 4 (see item 25). An activity is only a ‘petroleum activity’ if it is operations or works undertaken in an offshore area. Therefore, the activities that are, or are part of, an offshore project can also only be operations or works undertaken in an offshore area. Any component of a development that is undertaken in State or Territory coastal waters or onshore will not be part of an offshore project, unless the relevant State or Territory also confers environmental management functions to NOPSEMA under its legislation.

 

An ‘offshore project’ is a project consisting of activities undertaken for the recovery of petroleum other than on an appraisal basis, including any conveyance of recovered petroleum by pipeline. Specifically, an offshore project can include one or more of the following: drilling; construction of facilities or pipelines; operation of facilities or pipelines; and other petroleum activities undertaken for the purpose of the recovery of petroleum other than on an appraisal basis. An offshore project does not include drilling for exploration or appraisal purposes, or other petroleum exploration activities such as seismic surveys. Greenhouse gas activities are not included in the definition of ‘offshore project’. Decommissioning activities do not themselves fall within the definition of an offshore project, but require consideration in an ‘offshore project proposal’.

 

Offshore project proposal

An ‘offshore project proposal’ is the document submitted to the Regulator by a proponent when seeking acceptance for an ‘offshore project’. It describes those projects, from initial phases (e.g. construction) through to decommissioning – see Part 1A (item 35). Proponents are also able to submit an offshore project proposal for activities that are not, or are not part of, an offshore project, but this is not a requirement, and there is no direct legal consequence for not doing so – see regulation 5F (item 35).

 

Item [24] – Subregulation 4(1) (definition of operator)

 

This item repeals the definition of ‘operator’, as the Regulation removes the concept of an ‘operator’ from the Principal Regulations. Instead, the titleholder under whose title an activity is undertaken is made responsible for compliance with the Regulations.

 

Previously, the Principal Regulations placed key obligations on the operator of an activity. For example, it was the operator that was obliged to submit an environment plan to the Regulator before commencing an activity. An operator was guilty of an offence if the operator carried out an activity and there was no environment plan in force for the activity, or if the operator carried out the activity in a way that was contrary to the environment plan in force.

 

The concept of an ‘operator for an activity’ was unique to the Principal Regulations, and was not defined or recognised in the OPGGS Act or other regulations under the OPGGS Act. An ‘operator for an activity’ under the Principal Regulations was different to the facility operator that is defined for the purposes of occupational health and safety regulation under the OPGGS Act and the Safety Regulations. (The facility operator concept is required for reasons that are unique to occupational health and safety and that have no parallel in environmental management).

 

The review of the Principal Regulations determined that placing key obligations on an ‘operator’ for an activity is a major design weakness in the regime established by the Regulations. For example, there was no requirement that the operator would have any particular technical or financial capability, and so have the capacity to comply with the requirements of the Regulations. In addition, since the operator was responsible to the titleholder for the overall management of the activity, the operator would not in practice have had the independent capacity to ensure that operations complied with the environment plan, as it would always be the titleholder that exercised ultimate control. The titleholder, on the other hand, was not made responsible by the Regulations, even though it was the titleholder’s activities that created the environmental risk. The person who was instead made responsible by the Regulations would not have necessarily had either the resources or the level of control over the carrying out of the activity to enable that person to comply with the person’s responsibilities under the Regulations. It could even have been difficult in particular instances to identify who the operator was.

 

It is also notable that, under the OPGGS Act, the titleholder is responsible for compliance with the OPGGS Act and regulations, and may face potential consequences for non-compliance. In particular, non-compliance with the OPGGS Act and regulations is grounds for the Joint Authority to cancel a title or refuse to renew a petroleum exploration permit or petroleum retention lease. This is one of the most effective incentives to comply with the regulatory regime, given the substantial investments involved in offshore petroleum activities carried out under a title. However, the titleholder is responsible for compliance, and may face consequences for non-compliance, to the extent that the OPGGS Act and regulations place obligations on the titleholder specifically. Therefore, this link to the regulations, and the ability to cancel a title or refuse to renew a title as a result of a failure to comply with the regulations, arguably only has effect when there are obligations placed directly on the titleholder by the regulations. As discussed, however, the key obligations under the Principal Regulations were not previously placed on the titleholder. The titleholder was therefore not made responsible for non-compliance, either directly under the Regulations or indirectly through the potential consequences for failure to comply with regulatory requirements through the OPGGS Act. This was an untenable outcome in policy terms.

 

This was even more significant in the context of recent amendments to the OPGGS Act to include an express ‘polluter pays’ requirement, which makes the titleholder responsible to control and clean-up an escape of petroleum, remediate the environment and monitor the effects of the escaped petroleum, in accordance with the environment plan for the activity, including payment of all costs. It was untenable that this requirement be placed on the titleholder under the OPGGS Act while the Principal Regulations placed responsibilities, including in relation to an environment plan, on someone other than the titleholder.

 

The transfer of responsibility from an operator to the titleholder may not change arrangements in terms of who physically carries out an activity in practice. It may, for example, be a contracted entity that carries out the activity or, if there are multiple registered holders of a single title, one of those registered holders. However, regardless of the entity that physically carries out the activity, the amendments to the Principal Regulations ensure that the titleholder will be legally responsible for compliance with the Regulations. If there are multiple holders of a title, ‘the titleholder’ would refer to all of the members of the titleholder group together.

 

Item [25] – Subregulation 4(1) (definition of petroleum activity)

 

This item amends the definition of ‘petroleum activity’ in the Principal Regulations.

 

In its previous form, the definition was sufficiently broad to include activities relating to petroleum exploration or development other than those carried out under the authority of a title. This created uncertainty in terms of which activities were covered by the definition in practice, and in some cases resulted in the application of the Regulations to activities that have little relation to exploration for, or development of petroleum, or that are more appropriately classified as ordinary maritime activities. Such activities are inappropriate to be governed by the offshore petroleum regulatory regime.

 

The former definition also allowed for a possibility that there may not be a titleholder for a particular activity. However, given the removal of the concept of an ‘operator’ from the Regulations (see item 24), the new definition also clearly links a petroleum activity to the rights and obligations of a titleholder under the OPGGS Act and regulations.

 

The review of the Principal Regulations considered the definition of ‘petroleum activity’ with a view to clarifying and reducing the scope of the definition, to ensure it would not potentially capture ordinary maritime activities. The new definition removes the reference in the current definition to ‘any activity relating to petroleum exploration or development which may have an impact on the environment’. This narrows the scope of the definition.

 

Overall, the effect of this amendment is to ensure that the Principal Regulations do not regulate activities beyond the scope of the OPGGS Act.

 

A list of indicative exclusions from the definition was considered, including proposed exclusions provided by industry during consultation on the review of the Regulations. However, as the new definition sufficiently reduces the scope for inclusion of activities that should not require an environment plan under the Regulations, a list of exclusions was not included within the definition.

 

Under the new definition, only operations or works carried out in an offshore area may be a ‘petroleum activity’ for the purposes of the Regulations. Such operations or works are a petroleum activity if they are carried out for the purpose of:

(a)    Exercising a right conferred on a petroleum titleholder under the Act by a petroleum title; or

(b)   Discharging an obligation imposed on a petroleum titleholder by the Act or a legislative instrument under the Act.

 

The OPGGS Act specifies the rights conferred on a petroleum titleholder by a petroleum title. For example, section 98 of the OPGGS Act sets out the rights conferred by a petroleum exploration permit on a permittee, including to explore for petroleum in the permit area, to recover petroleum on an appraisal basis in the permit area, and to carry on such operations and execute such works in the permit area as are necessary for those purposes. Therefore, for example, a seismic survey carried out under a petroleum exploration permit is a petroleum activity as it is an operation carried out in an offshore area for the purpose of exploration for petroleum.

 

As another example, section 161 sets out rights conferred by a petroleum production licence on a licensee, including to recover petroleum in the licence area, and to carry out such operations and execute such works in the licence area as are necessary for the purpose of the rights conferred by the licence. Therefore, for example, construction and operation of a production facility are petroleum activities as they are operations or works carried out in an offshore area for the purpose of recovery of petroleum.

 

Where a right conferred by a title includes the right to explore for petroleum in the title area, the extended meaning of ‘explore’ in section 19 of the OPGGS Act should be taken into account in determining whether particular operations or works are, or are not, a petroleum activity.

 

The reference to obligations imposed on a petroleum titleholder by the Act or a legislative instrument under the Act includes directions given to a titleholder by NOPSEMA or the responsible Commonwealth Minister under the OPGGS Act. For example, NOPSEMA may give a direction to a titleholder under section 585 of the OPGGS Act requiring the titleholder to remove property brought into the title area. The titleholder would be required to develop and submit an environment plan for acceptance by the Regulator prior to taking action to remove the property in accordance with the direction.

 

Certain directions (such as directions given under section 574, 574A or 576B) are specified to have effect, and must be complied with, despite anything in the regulations. Therefore if such a direction were given and required to be complied with within a short timeframe, such as an urgent direction given in the event of a significant incident, the titleholder would not be expected to have an accepted environment plan in force prior to undertaking the required action.

 

However, it should not lightly be assumed that a direction has been given with the intent that it is to be complied with regardless of any environmental impacts. Clearly, a direction requiring an action to be taken to deal with an emergency is intended to be complied with as soon as is practicable, whether or not the relevant action is covered by an environment plan. However, a direction given by the responsible Commonwealth Minister for a resource management purpose, for example, may specify a time for compliance that allows for an environment plan, or a revision, to be submitted and accepted by the Regulator. The direction must be complied with, but there may be different methods of compliance that have different environmental impacts. It will be a matter for the titleholder to ascertain, from the terms and circumstances in which a particular direction is given, whether the direction is intended by the person giving it to override the requirement in the Regulations to have an appropriate environment plan in place.

 

The reference to obligations in paragraph (b) of the definition does not include work program commitments or retention lease conditions as such; the OPGGS Act does not contain any provision specifically stating that a titleholder must comply with a condition of a title. The incentive to comply with title conditions lies in administrative powers such as the ability of the Joint Authority to start the cancellation process or to refuse a renewal of a title on the ground of non-compliance with a condition of the title.

 

This is not to suggest, however, that any operations or works carried out in an offshore area that are undertaken as a work program commitment, such as a seismic survey or drilling of a well, would not be a petroleum activity. These would be petroleum activities because they are carried out in an offshore area in exercise of a right conferred by a petroleum title (fulfilling paragraph (a) of the new definition of ‘petroleum activity’). In each case, the titleholder would need to consider what they are actually required to do by the condition, and whether that would be a ‘petroleum activity’ in accordance with the definition. Obviously, an activity that does not take place in an offshore area, such as reprocessing seismic data, will not be a ‘petroleum activity’ simply because it is undertaken to satisfy a work program condition.

 

Item [26] – Subregulation 4(1) (definition of petroleum instrument)

 

This item repeals the definition of ‘petroleum instrument’. The Principal Regulations previously referred to an ‘instrument’ and ‘instrument holder’, whereas the OPGGS Act and other regulations under that Act refer to a ‘title’ and ‘titleholder’. For consistency, the definition of ‘petroleum instrument’ has therefore been repealed and a definition of ‘petroleum title’ has been inserted by item 28.

 

Item [27] – Subregulation 4(1) (definition of petroleum instrument holder)

 

This item repeals the definition of ‘petroleum instrument holder’. The Principal Regulations previously referred to an ‘instrument’ and ‘instrument holder’, whereas the OPGGS Act and other regulations under that Act refer to a ‘title’ and ‘titleholder’. For consistency, the definition of ‘petroleum instrument holder’ has therefore been repealed and a definition of ‘petroleum titleholder’ has been inserted by item 28.

 

Item [28] – Subregulation 4(1)

 

This item inserts definitions of ‘petroleum title’ and ‘petroleum titleholder’ in the Principal Regulations.

 

The Principal Regulations previously included definitions of ‘petroleum instrument’ and ‘petroleum instrument holder’, which were repealed by items 26 and 27 – see discussion in relation to those items. The main difference between the former definitions and the new definitions is the inclusion of a petroleum scientific investigation consent as a petroleum title and, consequently, a holder of a petroleum scientific investigation consent as a petroleum titleholder. Activities such as a seismic survey, which may have an impact on the environment, may be undertaken under a petroleum scientific investigation consent. It is therefore appropriate that relevant activities undertaken under a petroleum scientific investigation consent require an environment plan to be developed, and accepted by the Regulator, prior to undertaking the activity. 

 

Item [29] – Subregulation 4(1) (definition of produced formation water)

 

This item repeals the definition of ‘produced formation water’. Prescriptive requirements relating to discharge of produced formation water have been removed from the Principal Regulations – see item 91.

 

Item [30] – Subregulation 4(1)

 

This item inserts a definition of ‘proponent’ in the Regulations for the purposes of the new Part 1A – see item 35.

 

Item [31] – Subregulation 4(1) (definition of recordable incident)

 

This item amends the definition of ‘recordable incident’ in the Principal Regulations, so that it includes any breach of an environmental performance outcome or environmental performance standard, in the environment plan that applies to an activity, that is not a reportable incident (as defined in regulation 4).

 

Under regulation 26B, the titleholder of an activity must submit written reports of recordable incidents that occurred in relation to the activity during a calendar month as soon as practicable, but not later than 15 days, after the end of that month.

 

‘Recordable incident’ was previously defined as an incident arising from an activity that breaches a performance objective or standard in the environment plan that applies to the activity, and is not a reportable incident. Previously, in practice, petroleum companies defined ‘incidents’ differently depending on severity and type, and this led to a wide range of environmental incidents being reported under regulation 26B. Additional clarity on what is meant by a ‘recordable incident’ will help minimise uncertainty in interpretation of the Principal Regulations, and lead to more consistent reporting of these incidents.

 

The new definition therefore removes the reference to ‘an incident arising from the activity’ in the definition, and provides that any breach of an environmental performance outcome or standard that is not a reportable incident is a ‘recordable incident’, that will need to be reported in accordance with regulation 26B.

 

Item [32] – Subregulation 4(1) (definition of reportable incident)

 

This item removes the reference to an operator of an activity in the definition of ‘reportable incident’ in the Principal Regulations. The concept of an ‘operator’ has been removed from the Regulations, and the titleholder made responsible for compliance with the Regulations – see item 24.

 

Item [33] – Subregulation 4(1)

 

Previously, the Principal Regulations referred to an ‘instrument holder’, whereas the OPGGS Act and other regulations under that Act refer to a ‘titleholder’. For consistency, this item inserts a definition of ‘titleholder’ in the Regulations, and the definition of ‘instrument holder’ has been repealed by item 21. Amendments have also been made to references to an ‘instrument holder’ throughout the Principal Regulations, to replace them with references to a ‘titleholder’.

 

Item [34] – Subregulation 4(2)

 

This item repeals subregulation 4(2), including the Note. Subregulation 4(1) becomes regulation 4 – see item 3.

 

Subregulation 4(2) provided that a definition in the Principal Regulations applies to each use of the word or expression in the Regulations unless the contrary intention appears. However, subregulation 4(1) already expressly provided that the definitions of words or expressions in that subregulation apply ‘unless the contrary intention appears’. Subregulation 4(2) was therefore superfluous.

 

The Note was removed as it is considered unnecessary, and the list of example words and expressions were not up-to-date; for example, terms were listed that are not used in the Principal Regulations at all. To avoid having to check the currency of the list each time amendments are made, and given that the Note is not strictly necessary, the Note is repealed by this item.

 

Item [35] – After Part 1

 

This item inserts a new Part 1A (regulations 5A to 5F) into the Principal Regulations, relating to offshore project proposals.

 

New Part 1A requires submission of, public consultation on, and assessment and acceptance of an ‘offshore project proposal’, prior to the submission and assessment of an environment plan for petroleum activities that are, or are part of, an offshore project. (‘Offshore project’ and ‘offshore project proposal’ are defined in regulation 4 – see item 23.)

 

The purpose of the new Part, which is intended to deliver the same environmental outcomes as the existing process for environmental assessments under the EPBC Act, is to achieve the following:

·         Provide an environmental assessment process to capture large-scale petroleum developments that are likely to have significant impact on matters protected under Part 3 of the EPBC Act;

·         Provide the public an opportunity to review and provide input during the development of proposed offshore petroleum development projects;

·         Allow the Regulator to make a whole-of-project assessment of the acceptability of proposed offshore projects; and

·         Provide certainty to industry, through the Regulator’s decision on the acceptability of an offshore project, to inform and facilitate industry’s investment decisions.

 

The provisions in this part facilitate the implementation of the Australian Government’s commitment to streamline offshore petroleum and greenhouse gas environmental approvals. They allow the Minister for the Environment to issue a class approval for petroleum and greenhouse gas activities as actions or classes of actions such that proponents will have deemed approval under Part 9 of the EPBC Act for these activities. Following the Minister for the Environment’s approval, proponents no longer need to consider referral or seek approval for projects on a case by case basis as long as proponents meet the requirements under the Principal Regulations as amended by the Regulation.

 

New provisions inserted by items 42 and 54 support the requirements of new Part 1A by ensuring that an environment plan or proposed revision of an environment plan that includes one or more new activities that are, or are part of, an offshore project may not be submitted, and must not be assessed by the Regulator, unless either:

(a)    There is an accepted offshore project proposal that includes the activity (the accepted proposal may include only that activity, or other activities in addition to that activity); or

(b)   The Environment Minister has approved the taking of an action that is equivalent to or includes the activity under Part 9 of the EPBC Act, or has made a decision that an action that is equivalent to or includes the activity is not a controlled action (including if undertaken in a particular manner).

 

Therefore, a person who proposes to undertake one or more activities that are, or are part of, an offshore project, and who does not have a relevant decision of the Environment Minister under the EPBC Act as described above, must first submit and receive acceptance for an offshore project proposal and then subsequently submit and receive acceptance of an environment plan before they commence the activity (noting it is an offence for a titleholder to undertake an activity without an environment plan in force for the activity – see regulation 6 (item 36)).

 

Regulation 5A – Submission of an offshore project proposal

Regulation 5A sets out the requirement for a person to submit an offshore project proposal before commencing an offshore project, and the content requirements for an offshore project proposal. A fee is payable for the Regulator’s consideration of the proposal – see item 91.

 

Due to the long lead times associated with offshore projects, any person, rather than the titleholder for an activity that is or is part of an offshore project, is able to submit an offshore project proposal to the Regulator for assessment. If a person was not able to submit and consult on an offshore project proposal until a title was granted, this could cause lengthy delays and costs for offshore projects.

 

The person who submits the proposal (defined by regulation 4 as the ‘proponent’ – see item 30) may be an individual or a company that is proposing to undertake an offshore project. It is generally anticipated that the person who would have submitted a referral under the EPBC Act will be the person who submits an offshore project proposal to the Regulator.

 

As discussed above, an environment plan for an activity that is, or is part of, an offshore project may be submitted only if there is an accepted offshore project proposal, or a relevant decision of the Environment Minister. Therefore, if a proponent has obtained a relevant decision of the Environment Minister, they would not be required to develop and submit an offshore project proposal. This is made clear by subregulation 5A(2).

 

Under section 146D of the EPBC Act, an approval by the Environment Minister under section 146B of that Act (approval of an action taken in accordance with an endorsed policy, plan or program) is taken to be an approval of the taking of that action under Part 9 of that Act.

 

However, subregulation 5A(3) specifies that, for the purposes of paragraph 5A(2)(c), an approval by the Environment Minister under section 146B of the EPBC Act is not taken to be an approval of the taking of an action under Part 9 of that Act. Classes of actions approved under section 146B of the EPBC Act do not exempt proposed actions under the Principal Regulations from preparing and submitting an offshore project proposal for assessment and acceptance. Activities that are, or are part of, an offshore project would themselves be approved under section 146B of the EPBC Act if the Regulator accepts an offshore project proposal that includes the activity, and subsequently accepts an environment plan that relates to the activity, under the Principal Regulations.

 

A number of the content requirements for an offshore project proposal mirror the content requirements for an environment plan. It is acknowledged that a proposal is prepared at an earlier stage, however, and therefore the level of detail required to be included in relation to certain aspects of an offshore project may be less than is required in an environment plan.

 

Subparagraph 5A(5)(b)(v) requires a summary of the project to include a description of the actions proposed to be taken, following completion of the project, in relation to the facilities that are proposed to be used to undertake each activity that is part of the project. This would include, for example, proposed decommissioning activities in relation to those facilities. It should be noted that an offshore project proposal is not mandatory for decommissioning activities (although persons may elect to submit an offshore project proposal under regulation 5F); therefore an accepted proposal is not required for a titleholder to submit an environment plan for a decommissioning activity. However, it is expected that an offshore project proposal for activities that do require a proposal to be developed and accepted would include details of proposed decommissioning activities.

 

Subregulation 5A(6) specifies that the particular relevant values and sensitivities of an environment, which are required to be detailed in an offshore project proposal under paragraph 5A(5)(d), may include one or more of the matters of national environmental significance listed in that subregulation. If one or more of the listed matters may be affected by the project, the proposal must include relevant details. Potential impacts on the environment, including on matters of national environmental significance, and the environmental performance outcomes defined in the offshore project proposal in relation to those impacts, would be taken into account by the Regulator when deciding firstly whether a proposal is suitable for publication, and secondly whether to accept the offshore project proposal.

 

Regulation 5B – Further information

If a proponent submits an offshore project proposal to the Regulator, regulation 5B enables the Regulator to request further written information about any matter required by regulation 5A to be included in the proposal. This ensures that if a submitted proposal does not include relevant information, the Regulator may request the information, and consider the information as if it had been included in the submitted proposal, rather than being required by paragraph 5C(1)(b) to make a decision that the proposal is not suitable for publication.

 

The Regulator may request further written information more than once prior to making a decision that the proposal is or is not suitable for publication. Each request would need to be in writing, set out each matter for which information is requested, and specify a reasonable period within which the information is to be provided.

 

For the information to be considered by the Regulator, the proponent must provide the information within the period specified by the Regulator in the request, or a longer time agreed with the Regulator. If the proponent provides only some of the information requested by the Regulator, the information that is provided is to be given regard to as if it had been included in the submitted proposal.

 

Under subregulation 5C(1), the Regulator has 30 days after receiving an offshore project proposal to make a decision as to whether the proposal is, or is not, suitable for publication. The ability for the Regulator to request further written information under regulation 5B does not change this 30 day timeframe. However, if the Regulator requests further information, and the time to receive and consider that information would be longer than 30 days after the Regulator receives the proposal, the Regulator has the ability to make a decision under paragraph 5C(1)(c) that it is unable to make a decision on the proposal within the 30 day period and give the proponent notice in writing to this effect, setting out a proposed timetable for consideration of the proposal.

 

Regulation 5C – Suitability of offshore project proposal for publication

Regulation 5C sets out: the timeframe for the Regulator to make a decision as to whether an offshore project proposal is suitable for publication; the criteria for a determination that a proposal is suitable for publication; and the effect of a decision that a proposal is, or is not, suitable for publication.

 

Similar to an environment plan, the Regulator has 30 days after an offshore project proposal is submitted to decide that the proposal is, or is not, suitable for publication. Alternatively, if the Regulator is unable to make a decision within 30 days, the Regulator is required to give the proponent notice in writing to this effect, and set out a proposed timetable for consideration of the proposal.

 

Subregulation 5C(5) makes it clear, however, that a decision by the Regulator that a proposal is, or is not, suitable for publication is not invalid only because the Regulator did not meet the 30 day period to make a decision. This ensures that the validity of all decisions is maintained.

 

If the Regulator is reasonably satisfied that the proposal meets the criteria in subregulation 5C(2), the Regulator must decide that the proposal is suitable for public consultation. On the other hand, if the Regulator is not reasonably satisfied that the proposal meets the criteria, it must decide that the proposal is not suitable for publication.

 

The criteria in subregulation 5C(2) includes that the proposal appropriately identifies and evaluates the environmental impacts and risks of the project, sets out relevant environmental performance outcomes that are consistent with the principles of ecologically sustainable development, and sufficiently addresses the matters required by regulation 5A.

 

The criteria also includes that a proposal cannot be suitable for publication if the proposal involves an activity, or any part of an activity, being conducted in any part of a declared World Heritage property (within the meaning of the EPBC Act). The Australian Government has committed through international agreements that it will not allow mineral exploration or exploitation activities to be undertaken within the boundaries of a declared World Heritage property. The prohibition applies even if the Regulator is reasonably satisfied that the plan meets the other criteria in subregulation 5C(2).

 

The prohibition does not apply in relation to activities to be carried out outside of, but proximate to, a World Heritage property; proposals that include such activities must be determined to be suitable for publication if the Regulator is reasonably satisfied that the plan meets the criteria in subregulation 5C(2).

 

If the Regulator decides that the proposal is suitable for publication the Regulator must, as soon as practicable, publish the proposal on its website, and publish a notice inviting the public to comment on the proposal and explaining how to give comments. Comments given will inform how the proponent finalises the proposal – see subregulation 5D(1).

 

The notice must specify a period of at least four weeks for the public to give comments. The period specified will depend on various factors, such as the complexity of the project, the sensitivity of the environment in which the project is proposed to be undertaken, and the amount of consultation the proponent has already undertaken during development of the offshore project proposal. No maximum period for public comment is specified by the Regulations, to ensure the flexibility to determine an appropriate period on a case by case basis. However, the period for public comment will be fixed at the outset of each public comment period, to ensure certainty for industry and stakeholders in relation to the length of that public comment period.

 

If the Regulator decides that the proposal is not suitable for publication, the Regulator must notify the proponent of the decision as soon as practicable. If the proponent still wishes to proceed with the project, it will need to submit a new offshore project proposal under regulation 5A, noting that the proponent cannot have an environment plan for an activity that is or is part of that offshore project assessed until the Regulator has accepted an offshore project proposal that includes that activity.

 

Regulation 5D – Actions after publication of offshore project proposal

Regulation 5D sets out the roles and responsibilities of the proponent and the Regulator after the period specified for public comment on an offshore project proposal under subparagraph 5C(3)(b)(ii) has ended.

 

The proponent may elect to alter the content of the proposal in response to feedback received during the period for public comment. Whether the proposal is altered or not, the proponent must give the Regulator another copy of the proposal. Requiring another copy of the proposal to be submitted to the Regulator, even if the proposal has not changed, ensures that the Regulator is aware that the proponent is continuing with the proposal.

 

Along with the copy of the proposal, the proponent must submit to the Regulator a summary of all comments received during the period of public comment, an assessment of the merits of each objection or claim about the project, and a statement of the proponent’s proposed response to each of those objections or claims. This may include a nil response, with a supporting explanation, or a demonstration of any changes made to the proposal as a result of an objection or claim.

 

Subregulation 5D(1) requires that the proponent give the Regulator another copy of the proposal (altered or otherwise) and the additional information required ‘as soon as practicable’ after the end of the period of public comment. In this context, this means in effect that the proponent may alter and submit another copy of the offshore project proposal to the Regulator as soon as the proponent is ready to do so.

 

If the proponent gives the Regulator a copy of the proposal, subregulation 5D(2) enables the Regulator to request further written information about any matter required by regulation 5A to be included in the proposal, or any matter required by paragraph 5D(1)(c) to be included with a copy of the proposal (i.e. the summary and assessment of public comments and proposed actions in response). This will ensure that if a submitted proposal does not include relevant information, the Regulator may request the information, and consider the information as if it had been included in or with (as applicable) the submitted proposal, rather than being required by paragraph 5D(5)(b) to make a decision to refuse to accept the proposal.

 

The Regulator may request further written information more than once prior to making a decision to accept or refuse to accept the proposal. Each request would need to be in writing, set out each matter for which information is requested, and specify a reasonable period within which the information is to be provided.

 

For the information to be considered by the Regulator, the proponent must provide the information within the period specified by the Regulator in the request, or a longer time agreed with the Regulator. If the proponent provides only some of the information requested to be provided, the information that is provided is to be given regard to as if it had been included in or with (as applicable) the submitted proposal.

 

Under subregulation 5D(5), the Regulator has 30 days after receiving a copy of an offshore project proposal to make a decision in relation to the proposal. The ability for the Regulator to request further written information under subregulation 5D(2) does not change this 30 day timeframe. However, if the Regulator requests further information, and the time to receive and consider that information would be longer than 30 days after the Regulator receives the copy of the proposal, the Regulator has the ability to make a decision under paragraph 5D(5)(c) that it is unable to make a decision on the proposal within the 30 day period and give the proponent notice in writing to this effect, setting out a proposed timetable for consideration of the proposal.

 

Similar to an environment plan, the Regulator has 30 days after a copy of the offshore project proposal is submitted to decide whether to accept or refuse to accept the proposal. Alternatively, if the Regulator is unable to make a decision within 30 days, the Regulator is required to give the proponent notice in writing to this effect, and set out a proposed timetable for consideration of the proposal.

 

Subregulation 5D(9) makes it clear, however, that a decision by the Regulator to accept, or refuse to accept, a proposal is not invalid only because the Regulator did not meet the 30 day period to make a decision. This ensures that the validity of all decisions is maintained.

 

If the Regulator is reasonably satisfied that the proposal meets the criteria in subregulation 5D(6), the Regulator must accept the proposal. On the other hand, if the Regulator is not reasonably satisfied that the proposal meets the criteria in subregulation 5D(6), it must refuse to accept the proposal.

 

The criteria for final acceptance of an offshore project proposal differs in some respects to the criteria for deciding that a proposal is suitable for publication. For example, the criteria for final acceptance includes that the proposal adequately addresses comments given during the period for public comment. The criteria also includes that the proposal is suitable for the nature and scale of the project, and sets out appropriate environmental performance outcomes that demonstrate the environmental impacts and risks of the project will be managed to an acceptable level. As with the criteria for deciding whether a proposal is suitable for publication, a proposal cannot be accepted if it would involve an activity, or any part of an activity, being conducted within any part of a declared World Heritage property.

 

If the Regulator accepts the proposal, the Regulator must publish the accepted proposal on its website within 10 days.

 

If the Regulator refuses to accept the proposal, the Regulator must notify the proponent of the decision as soon as practicable. The Regulator is also be required to publish a notice on its website setting out that it has refused to accept the proposal, and the reasons for the decision, as soon as practicable after making the decision.

 

If the proponent still wishes to proceed with the project encompassing one or more activities that are carried out for the purpose of recovery of petroleum, other than on an appraisal basis, including any conveyance of recovered petroleum by pipeline, it needs to submit a new offshore project proposal under regulation 5A and commence the process again, including public comment on the new proposal. The proponent cannot have an environment plan for an activity that is or is part of that offshore project assessed until the Regulator has accepted an offshore project proposal that includes that activity.

 

If the proponent had submitted a proposal for an activity or activities that do not fall within the definition of an offshore project, and the proponent still wishes to proceed with the activity or activities following refusal to accept the proposal, the proponent is not obliged to submit a new proposal under regulation 5A, although it may do so. See further discussion under this item in relation to regulation 5F.

 

The Regulation does not provide for merits review of a decision by the Regulator to accept, or refuse to accept, an offshore project proposal. There appears to be no tribunal established under Commonwealth legislation that would have the necessary environmental credentials, and there is not one that combines expertise in environmental regulation and offshore petroleum operations. Even if it were possible to put together a group of appropriately-qualified persons who were members of the Administrative Appeals Tribunal, they would be unlikely to have a flow of work that would enable them to build and maintain their expertise. Added to that is the difficulty of assembling such a group of persons within the very short timeframe necessary to review a decision, given the very high cost of delaying offshore operations even for a short time.

 

Regulation 5E – Withdrawal of offshore project proposal

Regulation 5E provides a specific ability for a proponent to withdraw an offshore project proposal it has submitted to the Regulator, at any time before the Regulator has made a final decision under regulation 5D to accept or refuse to accept the proposal. This may be before or after the proposal has been published for public comment.

 

If the proponent withdraws the submitted proposal after the proposal has been published on the Regulator’s website for public comment, the Regulator must publish on its website a notice that the proposal has been withdrawn. However, the Regulator would not do so if a proposal is withdrawn before being published for public comment.

 

If the titleholder withdraws the submitted proposal, the Regulator would cease its consideration of the proposal, and no further amount would be added to the fee payable by the proponent under regulation 32 (see item 91).

 

Regulation 5F – Use of the offshore project proposal system for other activities

Regulation 5F enables a person who is proposing to undertake an activity that is not, or is not part of, an offshore project to voluntarily submit a document that is equivalent to an offshore project proposal to the Regulator, and request the Regulator to consider the proposal in accordance with regulations 5A to 5D.

 

A person may submit a voluntary proposal if they propose to undertake one or more activities for at least one of the following purposes:

·         Exploration for petroleum;

·         Recovering petroleum on an appraisal basis;

·         Exploration for a potential greenhouse gas storage formation;

·         Exploration for a potential greenhouse gas injection site;

·         Injecting or storing, on an appraisal basis, a greenhouse gas substance in a part of a geological formation;

·         Injecting or permanently storing a greenhouse gas substance into an identified greenhouse gas storage formation (within the meaning of section 312 of the OPGGS Act);

·         Conveyance of a greenhouse gas substance by pipeline;

·         Decommissioning a facility, petroleum pipeline or greenhouse gas pipeline.

 

If a person submits a voluntary proposal, subregulations 5A(4) to (8), regulations 5B to 5E and regulation 32 apply to the proposal as if it were an offshore project proposal, and the activity or activities were an offshore project. A fee would therefore be payable for the Regulator’s consideration of the proposal – see item 91.

 

In effect, there is no direct legal consequence of a decision by the Regulator to accept or refuse to accept a proposal that is submitted on a voluntary basis. For example, a decision to refuse to accept the proposal does not prevent the person submitting an environment plan for the activity, and having the plan assessed by the Regulator. The proponent may choose to either submit a new offshore project proposal, or proceed directly to submission of an environment plan. Without changes to the proposed environmental management of the activity in the environment plan compared to the rejected proposal, however, it is unlikely that the plan would meet the acceptance criteria for an environment plan in regulation 10A. The statement of reasons provided by the Regulator in refusing to accept a proposal (see subregulation 5D(8)) provides the information required for the proponent to determine the next course of action, if any.

 

Although there is no direct legal effect of a decision by the Regulator in relation to a voluntary proposal, a person may elect to voluntarily prepare and submit a proposal for an activity for several reasons. For example, it enables the person to have the Regulator consider the proposed activity, and high-level details of proposed environmental management of the activity, prior to making a final investment decision in relation to the activity. If the Regulator refuses to accept the voluntary proposal, this indicates to the person who submitted that the proposal that the activity should not proceed at all, or without changes being made to the proposed activity and/or the proposed environmental management of the activity.

 

A person may also elect to submit a voluntary proposal in order to use the formal process in regulation 5C for public comment on the proposal, in particular for activities that are proposed to be undertaken in relatively sensitive environments.

 

Item [36] – Subregulation 6(1)

 

This item removes the reference to an operator of an activity in regulation 6, and replaces it with a reference to a titleholder, so that a titleholder commits an offence if it undertakes an activity and there is no environment plan in force for the activity. The concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance with the Regulations – see item 24.

 

This change to making the titleholder responsible for compliance with the Regulations aligns the Regulations with the OPGGS Act. Under the Act, a title authorises the titleholder to carry out the particular offshore operations specified in the Act for each kind of title. It does not matter who the person (individual or corporate) is who physically carries out an activity.  Under the Act, and now under the Regulations, an activity carried out under the authority of a title is taken to be carried out by the titleholder. This is because all activities are carried out, whether directly or indirectly, at the behest of the titleholder, who is the person who has the legal authority to exercise the rights conferred by the title and who is, ultimately, the person exploiting those rights.

 

The penalty for a failure to comply with subregulation 6(1) remains at 80 penalty units, or 400 penalty units for an offence committed by a body corporate due to the operation of subsection 4B(3) of the Crimes Act 1914, and the offence continues to be an offence of strict liability. However, it is the titleholder who is responsible for compliance. It is still appropriate to apply strict liability to the offence to ensure that the regulation can be enforced more effectively as, given the remote and complex nature of offshore operations and the prevalence of multiple titleholder arrangements, it is extremely difficult to prove intent. The intention of the application of strict liability is therefore to improve compliance in the regulatory regime. This is consistent with the principles outlined in A Guide To Framing Commonwealth Offences, Infringement Notices and Enforcement Powers, September 2011, which include that the punishment of offences not involving fault may be appropriate where it is likely to significantly enhance the effectiveness of the enforcement regime in deterring certain conduct.

 

It is also appropriate to continue to apply a penalty of 80 penalty units, noting this is higher than the preference stated in the Guide for a maximum 60 penalty units for offences of strict liability. Offshore resources activities, as a matter of course, require a very high level of expenditure. Therefore by comparison a smaller penalty would be an ineffective deterrent, especially given the potential for severe risks or impacts to the environment if a titleholder fails to comply with subregulation 6(1). 

 


 

 Item [37] – Subregulation 7(1)

 

This item removes the reference to an operator of an activity in subregulation 7(1), and replaces it with a reference to a titleholder, so that a titleholder commits an offence if it undertakes an activity in a way that is contrary to the environment plan in force for the activity. The concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance with the Regulations – see item 24.

 

The commentary provided in item 36 in relation to subregulation 6(1) concerning the rights and responsibilities of the titleholder are also applicable to this subregulation.

 

The penalty for a failure to comply with subregulation 7(1) remains at 80 penalty units, or 400 penalty units for an offence committed by a body corporate due to the operation of subsection 4B(3) of the Crimes Act 1914, and the offence continues to be an offence of strict liability. However, it is the titleholder who is responsible for compliance. It is still appropriate to apply strict liability to the offence to ensure that the regulation can be enforced more effectively as, given the remote and complex nature of offshore operations and the prevalence of multiple titleholder arrangements, it is extremely difficult to prove intent. The intention of the application of strict liability is therefore to improve compliance in the regulatory regime. This is consistent with the principles outlined in A Guide To Framing Commonwealth Offences, Infringement Notices and Enforcement Powers, September 2011, which include that the punishment of offences not involving fault may be appropriate where it is likely to significantly enhance the effectiveness of the enforcement regime in deterring certain conduct.

 

It is also appropriate to continue to apply a penalty of 80 penalty units, noting this is higher than the preference stated in the Guide for a maximum 60 penalty units for offences of strict liability. Offshore resources activities, as a matter of course, require a very high level of expenditure. Therefore by comparison a smaller penalty would be an ineffective deterrent, especially given the potential for severe risks or impacts to the environment if a titleholder fails to comply with subregulation 7(1). 

 

Item [38] – Subregulation 7(2)

 

This item removes the reference to an operator in subregulation 7(2), and replaces it with a reference to a titleholder. The concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance with the Regulations – see item 24.

 

This item also inserts a note to explain that a defendant bears an evidential burden in relation to the matter in subregulation 7(2). This is not a new burden; therefore the note is added to inform the reader.

 

Items [39] and [40] – Subregulation 8(1) and Paragraph 8(1)(a)

 

These items remove references to an operator of an activity in subregulation 8(1), and replace it with references to a titleholder, so that a titleholder commits an offence if it undertakes an activity after the occurrence of any significant new environmental impact or risk, or any significant increase in an existing environmental impact or risk, not provided for in the environment plan in force for the activity. The concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance with the Regulations – see item 24.

 

The commentary provided in item 36 in relation to subregulation 6(1) concerning the rights and responsibilities of the titleholder are also applicable to this subregulation.

 

The penalty for a failure to comply with subregulation 8(1) remains at 80 penalty units, or 400 penalty units for an offence committed by a body corporate due to the operation of subsection 4B(3) of the Crimes Act 1914, and the offence continues to be an offence of strict liability. However, it is the titleholder who is responsible for compliance. It is still appropriate to apply strict liability to the offence to ensure that the regulation can be enforced more effectively as, given the remote and complex nature of offshore operations and the prevalence of multiple titleholder arrangements, it is extremely difficult to prove intent. The intention of the application of strict liability is therefore to improve compliance in the regulatory regime. This is consistent with the principles outlined in A Guide To Framing Commonwealth Offences, Infringement Notices and Enforcement Powers, September 2011, which include that the punishment of offences not involving fault may be appropriate where it is likely to significantly enhance the effectiveness of the enforcement regime in deterring certain conduct.

 

It is also appropriate to continue to apply a penalty of 80 penalty units, noting this is higher than the preference stated in the Guide for a maximum 60 penalty units for offences of strict liability. Offshore resources activities, as a matter of course, require a very high level of expenditure. Therefore by comparison a smaller penalty would be an ineffective deterrent, especially given the potential for severe risks or impacts to the environment if a titleholder fails to comply with subregulation 8(1). 

 

Item [41] – Subregulation 8(2)

 

This item amends subregulation 8(2) to replace references to the operator with a reference to the titleholder. The concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance with the Regulations – see item 24.

 

This item also amends subregulation 8(2) to specify that subregulation 8(1) does not apply only if the titleholder has submitted a proposed revision of the environment plan in force for an activity in accordance with subregulation 17(6), rather than regulation 17.

 

Under regulation 17 there is more than one circumstance in which a proposed revision of an environment plan is submitted (see item 54):

·         Subregulation 17(1) enables a titleholder to submit a proposed revision of an environment plan, with the Regulator’s approval, before the commencement of a new activity that is not provided for in the environment plan.

·         Subregulation 17(5) requires a titleholder to submit a proposed revision of an environment plan before any significant modification of or new stage of an existing activity that is not provided for in the environment plan.

·         Subregulation 17(6) requires a titleholder to submit a proposed revision of an environment plan before, or as soon as practicable after:

o   The occurrence of any significant new, or significant increase in an existing, environmental impact or risk, not provided for the in the environment plan; or

o   The occurrence of a series of new, or a series of increases in existing, environmental impacts or risks which, taken together, amount to the occurrence of a significant new or significant increase in an existing impact or risk that is not provided for in the environment plan.

·         Subregulation 17(7) requires a titleholder to submit a proposed revision of an environment plan as soon as practicable after a change in the titleholder, if the change will result in a change in the manner in which the environmental impacts and risks of the activity are managed.

 

Subregulation 8(2) previously referred to regulation 17 in its entirety, so that if the titleholder had submitted a revision as required under any of the circumstances mentioned above, they did not commit an offence if they continued to carry out an activity after the occurrence of a significant new, or significant increase in an existing, impact or risk. While this makes sense in the context of subregulation 17(6), which relates to increases in impacts or risk, it does not in the context of subregulations 17(1), (5) and (7). Effectively, a titleholder could argue that they can continue operating without committing an offence, despite a new or increased environmental impact or risk, because they had submitted a revision to an environment plan on the basis that they would be commencing a new activity, or because of a significant modification to or new stage of an existing activity. This was an unintended consequence of the regulation that did not align with the policy intent.  

 

The amendment in this item therefore specifies that a titleholder does not commit an offence under subregulation 8(1) if it submits a proposed revision of the environment plan in force for the activity in accordance with subregulation 17(6), and the Regulator has not refused to accept the revision.

 

This item also replaces the reference to regulation 17 in the Note to subregulation 8(2) with a specific reference to subregulation 17(6).

 

This item also adds an additional Note to explain that a defendant bears an evidential burden in relation to the matter in subregulation 8(2). This is not a new burden; therefore the note would be added to inform the reader.

 

Item [42] – Division 2.2

 

This item repeals Division 2.2 of the Principal Regulations and replaces it with a new Division 2.2 (regulations 9 to 11), to revise and clarify the process for submission, assessment and acceptance of an environment plan (including publication of summaries of accepted environment plans).

 

Regulation 9 – Submission of an environment plan

As for the previous subregulation 9(1), new subregulation 9(1) requires submission of an environment plan for an activity before the commencement of the activity; however under new subregulation 9(1) it is the titleholder, rather than the operator of the activity, that must submit an environment plan to the Regulator. This is to reflect amendments to remove the concept of an ‘operator’ from the Regulations, and make the titleholder responsible for compliance with the Regulations in relation to activities carried out under the authority of the title. A titleholder commits an offence if it undertakes an activity and there is no environment plan in force for the activity (subregulation 6(1) – see item 36).

 

Division 1 of Part 9.6A of the OPGGS Act (eligible voluntary action by multiple titleholders) applies to submission of an environment plan under subregulation 9(1), as submission of an environment plan to the Regulator under the Principal Regulations is an ‘eligible voluntary action’ for the purposes of that Division. This means that, if there are two or more registered holders of the title under which the proposed activity is to be undertaken, those holders of the title are not entitled to submit the environment plan unless they have provided a joint written notice to the National Offshore Petroleum Titles Administrator (the Titles Administrator) nominating one of them as being the person who is authorised to take eligible voluntary actions on behalf of the registered holders. The nominated person would need to be the person that submits the plan, and express the submission to be made on behalf of all of the registered holders of the title. 

 

The amendment to subregulation 9(1) does not prevent submission of an environment plan for an activity undertaken under the authority of more than one title, as the Principal Regulations are activity-based, rather than title-based (this is also made clear by new subregulation 9(7) – see discussion below). For example, if a seismic survey were to be undertaken across several exploration permits, under the authority of those permits (rather than under the authority of a petroleum access authority as discussed below), one environment plan can be submitted for the survey even if the permits are held by different titleholders. In practice, the survey operator would prepare the environment plan, and it would be submitted by each titleholder, in the sense that all their names and title details would be included in the submission. (Given the application of the multiple titleholder provisions in Part 9.6A of the OPGGS Act, the nominated titleholder to take eligible voluntary actions on behalf of each group of registered holders for a single title would need to ‘submit’ the plan by signing their name to the plan, and specifying that the submission is made on behalf of that titleholder group.) 

 

The plan would be treated by the Regulator as the environment plan for each of the titleholders; therefore correspondence, notices, etc, would be sent to all titleholders under whose title the activity will be undertaken. The titleholders would also be responsible for compliance with the environment plan, even though it may have been prepared by a survey operator, and that operator may themselves carry out the activity. Any failure of the seismic operator to comply with the accepted environment plan would be non-compliance by the titleholders or, if it is an isolated failure, the titleholder in whose title area the failure occurs.

 

If an environment plan is submitted for an activity that is undertaken under the authority of more than one title, environment plan levy would be imposed on all the titleholders jointly and severally – see paragraph 10F(3)(b) of the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Act 2003 (Regulatory Levies Act).

 

Alternatively, activities such as a multi-client seismic survey can be undertaken under a petroleum special prospecting authority, possibly together with a petroleum access authority where title areas are already covered by titles. In this case, the holder of the authority who will undertake the survey would themselves be the titleholder, and therefore responsible for submission of the environment plan and for compliance with the Regulations, as those authorities would be ‘titles’ for the purposes of the Principal Regulations. The authority holder would submit one environment plan to cover the seismic survey/s to be undertaken and would not need to submit a separate plan in relation to each specific title.

 

New subregulation 9(2) enables (but does not require) applicants for certain types of title to submit an environment plan to the Regulator, and obtain acceptance of the plan, prior to the grant of the title. The provisions in Divisions 2.2, 2.2A and 2.3 of the Principal Regulations then apply to the title applicant as if they were a titleholder.

 

If the Regulator accepts the environment plan before the title is granted, this does not give the applicant the authority to commence the activity to which the plan relates. The applicant does not have the authority to commence the activity unless and until the title is granted. However, obtaining acceptance of the plan prior to grant of the title enables the applicant to commence the activity as soon as the title is granted, rather than being required to submit the plan for acceptance after the title has been granted.

 

Specifically, subregulation 9(2) enables an applicant for a petroleum access authority, petroleum special prospecting authority, greenhouse gas search authority or greenhouse gas special authority to submit an environment plan to the Regulator. Given the generally short-term nature of these titles, it is beneficial to enable applicants for an authority to obtain acceptance of an environment plan prior to the grant of the title, so that the activity can commence as soon as the title is granted.

 

Subregulation 9(2) also enables an applicant for a pipeline licence to submit an environment plan to the Regulator. A pipeline licence is required by the OPGGS Act to contain specific details such as the route of the pipeline and whether it must be buried, which are also of an environmentally-relevant nature. A licence might state, for example, that a pipeline does not need to be buried, and then it could emerge in the environment plan consultation process that a pipeline laid on the seabed would impede fishing activities.

 

Enabling an applicant for a pipeline licence to submit an environment plan to the Regulator enables environmental matters to be taken into account prior to the grant of the title so that, matters can be specified in the title with full knowledge of relevant environmental issues. There is provision for a pipeline licence to be varied; however this could cause an increase in regulatory burden compared to having environmental acceptance of a pipeline proposal prior to finalising the grant of the pipeline licence. In any case, enabling an applicant for a pipeline license to submit an environment plan enables the applicant to themselves determine whether they prefer to submit the plan before or after grant of the title.

 

An applicant for a petroleum scientific investigation consent or greenhouse gas research consent does not have the ability to submit an environment plan to the Regulator until after the consent is granted. Unlike an authority granted under the OPGGS Act, which does not authorise making a well, there is nothing to prevent a consent holder being granted the ability to make a well. Therefore, as for other types of title that permit drilling of a well, an applicant for a consent is not be able to submit an environment plan until the consent has been granted.

 

The multiple titleholder provisions in Part 9.6A of the OPGGS Act do not apply to applicants for a title listed in subregulation 9(2). It is expected that if there were more than one applicant for a single title, each would sign the application for acceptance of the environment plan submitted to the Regulator.

 

Under new subregulation 9(3), a titleholder (or an applicant for a pipeline licence) may only submit an environment plan for an activity that is, or is part of, an offshore project (as defined in regulation 4 – see item 23) if any one of the following applies:

·         The Regulator must have previously accepted an offshore project proposal that includes the activity; or

·         The Environment Minister must have approved the taking of an action that is equivalent to or includes the activity under Part 9 of the EPBC Act; or

·         The Environment Minister must have made a decision that an action that is equivalent to or includes the activity is not a controlled action (section 75 of the EPBC Act) or is not a controlled action if undertaken in a particular manner (section 77A of the EPBC Act).

 

The effect of new subregulation 9(4) is that an environment plan for an activity submitted in contravention of subregulation 9(3) is taken not to have been submitted. Therefore, the plan cannot be considered by the Regulator, and the assessment and acceptance process in regulations 9A to 11 does not apply.

 

As the plan is taken not to have been submitted, environment plan levy would not be imposed.

 

It is an offence for a titleholder to undertake an activity without an environment plan in force for the activity (subregulation 6(1) – see item 36). Therefore, if the titleholder wishes to undertake the activity that is, or is part of, an offshore project, it needs to develop, submit, publicly consult on and obtain the Regulator’s acceptance of an offshore project proposal that includes that activity. It is intended that an offshore project proposal is only needed to be developed for that particular activity. Therefore if the activity were part of a broader development for which an offshore project proposal had been accepted, but the particular activity had not been included in the original proposal, the titleholder would not need to re-do the original proposal for all activities; just the new activity.

 

See also the discussion about offshore project proposals, and the policy rationale for requiring an offshore project proposal for offshore projects, under item 35.

 

Subregulations 9(3) and (4) do not apply to activities that are not, or are not part of, an offshore project, even if an offshore project proposal had been voluntarily prepared and submitted by the proponent in relation to that activity – see item 35 (regulation 5F).

 

Under section 146D of the EPBC Act, an approval by the Environment Minister under section 146B of that Act (approval of an action taken in accordance with an endorsed policy, plan or program) is taken to be an approval of the taking of that action under Part 9 of that Act.

 

However, new subregulation 9(5) specifies that, for the purposes of subparagraph 9(3)(b)(iii), an approval by the Environment Minister under section 146B of the EPBC Act is not be taken to be an approval of the taking of an action under Part 9 of that Act. Classes of actions approved under section 146B of the EPBC Act do not exempt proposed actions under the Principal Regulations from preparing and submitting an offshore project proposal for assessment and acceptance. Activities that are, or are part of, an offshore project are themselves approved under section 146B of the EPBC Act if the Regulator accepts an offshore project proposal that includes the activity, and subsequently accepts an environment plan that relates to the activity, under the Principal Regulations.

 

New subregulation 9(6) makes clear that an environment plan must be in writing.

 

New subregulation 9(7) combines current subregulation 9(2) and paragraph 9(3)(b) of the Principal Regulations, and also makes it clear that an environment plan may relate to more than one activity, or to an activity or activities to be undertaken under two or more titles, including where the titles are held by different titleholders, with the approval of the Regulator.

 

The ability to submit an environment plan that relates to more than one activity, or to an activity or activities to be undertaken under two or more titles held by different titleholders, is not new. However, new subregulation 9(7) ensures it is clear that plans may be submitted on that basis, with the approval of the Regulator.

 

It is not anticipated that a formal process would be required for approval. For example, the titleholder could agree with the Regulator whether a plan may relate to more than one activity, or to an activity or activities to be undertaken under two or more titles held by the same or different titleholders, prior to submitting the plan, or the Regulator could consider the matter when assessing the plan. This is a suitable topic for guidance issued by NOPSEMA.

 

In order to improve transparency in relation to proposed activities, new subregulation 9(8) requires the Regulator to publish certain information on its website as soon as practicable after an environment plan is submitted to the Regulator. This informs the public about the receipt of environment plans, and provides high level information about the activity to which the plan relates, to ensure the public is made aware of proposed activities prior to the acceptance of an environment plan. (Summaries of accepted environment plans continue to be required to be submitted and published under regulation 11 – see discussion below.)

 

Unlike publication of an offshore project proposal under regulation 5C (see item 35), publication of the information about an environment plan is not be an invitation for public comment. The information would be published to inform the public about proposed activities, and the status of the environment plan (e.g. whether the Regulator has accepted or refused to accept the plan). In order to have an environment plan accepted, titleholders are required under regulation 11A to consult with relevant persons during the development of the environment plan.

 

It is not required to publish of environment plans in full; plans contain commercially sensitive information, and may be quite detailed and technically complex.

 

If there is more than one registered holder of a title under the authority of which the activity to which a plan relates is to be carried out, the name of each of the registered holders of the title must be published under paragraph 9(8)(a).

 

The description of the activity or stage of the activity required under paragraph 9(8)(b) will be quite high level and detail the broad activity type.

 

New subregulation 9(9) provides a specific ability for a titleholder to withdraw an environment plan it has submitted to the Regulator, at any time before the Regulator has made a decision under regulation 10 to accept or refuse to accept the plan.

 

If the titleholder withdraws the submitted plan, the compliance amount of environment plan levy imposed on submission of the plan would be refunded (for any amount paid prior to withdrawal of the plan) and remitted (for amounts yet to be paid) – see item 101.

 

If an environment plan is withdrawn, the Regulator must publish a notice to this effect on its website (new subregulation 9(10)).

 

Regulation 9A – Further information

Although the Principal Regulations already provided for modification and resubmission of an environment plan if the Regulator was not reasonably satisfied that the plan met the acceptance criteria following its initial assessment of the plan, there was no specific provision that allowed flexibility for the Regulator to request additional information during its assessment of the plan. In comparison, regulation 2.25 of the Safety Regulations, which applies if a facility operator has submitted a safety case to NOPSEMA for assessment and acceptance, enables NOPSEMA to request further written information about any matter required by the Safety Regulations to be included in a safety case, before making a decision to accept or reject the safety case. If the facility operator provides the information as requested, the information becomes part of the safety case as if it had been included in the safety case as it was first submitted to NOPSEMA, and NOPSEMA must have regard to it.

 

New regulation 9A enables the Regulator to request further written information about any matter required by the Principal Regulations to be included in an environment plan, if a titleholder submits a plan to the Regulator. This ensures that if a submitted plan does not include relevant information, rather than being required to give the titleholder a notice under subregulation 10(2), or refuse to accept the plan, the Regulator may request the information, and consider the information as if it had been included in the submitted plan.

 

The Regulator may request further written information more than once prior to making a decision about the plan. Each request would need to be in writing, set out each matter for which information is requested, and specify a reasonable period within which the information is to be provided.

 

For the information to be considered by the Regulator, the titleholder must provide the information within the period specified by the Regulator in the request, or a longer time agreed with the Regulator. If the titleholder provides only some of the information requested to be provided, the information that is provided would be given regard to as if it had been included in the submitted plan.

 

Under subregulation 10(1) or 10(4), the Regulator has 30 days after receiving an environment plan or modified plan respectively to make a decision in relation to the plan. The ability for the Regulator to request further written information under regulation 9A does not change this 30 day timeframe. However, if the Regulator requests further information, and the time to receive and consider that information would be longer than 30 days after the Regulator receives the plan, the Regulator has the ability to make a decision under paragraph 10(1)(c) or 10(4)(c), as applicable, that it is unable to make a decision on the plan within the 30 day period and give the titleholder notice in writing to this effect, setting out a proposed timetable for consideration of the plan.

 

Regulation 10 – Making decision on submitted environment plan

On the whole, the process for assessment and decision-making in relation to an environment plan in new regulation 10 is largely unchanged from the former process. However, the new regulation clarifies the process, and also makes amendments to ensure that, when a titleholder is given an opportunity to modify and resubmit the plan, the Regulator must specify a timeframe for modification and resubmission, and the criteria about which the Regulator is not reasonably satisfied.

 

As was previously the case, the Regulator has 30 days after first receiving a plan to decide whether or not it is reasonably satisfied that the plan meets the acceptance criteria that are set out in regulation 10A. Alternatively, if the Regulator is unable to make a decision within 30 days, the Regulator is required to give the titleholder notice in writing to this effect, and set out a proposed timetable for consideration of the plan.

 

Subregulation 10(7) makes it clear, however, that a decision by the Regulator in relation to the plan is not invalid only because the Regulator did not meet the 30 day period to make a decision. This ensures that the validity of all decisions is maintained.

 

If the Regulator is reasonably satisfied that the plan meets the acceptance criteria in regulation 10A, the Regulator must accept the plan. On the other hand, if the Regulator is not reasonably satisfied that the plan meets the criteria, it must give the titleholder a notice under subregulation 10(2). The requirement in subregulation 10(1) that the Regulator be ‘reasonably satisfied’ that the environment plan meets the criteria set out in regulation 10A in order for the Regulator to accept the plan replaces the requirement previously in subregulation 11(1) that there be ‘reasonable grounds for believing’ that the plan meets the criteria.  The requirement has two elements:

(a)        the Regulator must be satisfied that the plan meets the criteria; and

(b)        that satisfaction must be reasonable.

 

This description in paragraph 10(1)(a) of the decision to be made matches that previously in subregulation 11(2) (new paragraph 10(1)(b)). Previously, the two were different, which was untenable, given that they refer to the same decision.

 

Subregulation 10(2) sets out the requirements for a notice given to the titleholder. In particular, the notice must identify the criteria in regulation 10A about which the Regulator is not reasonably satisfied, and set a date by which the titleholder may resubmit the plan for further assessment. The date specified needs to give the titleholder a reasonable opportunity to modify and resubmit the plan (subregulation 10(3)). If the titleholder does not resubmit the plan by the date referred to in the notice, or a later date agreed with the Regulator, the Regulator is required to refuse to accept the plan, accept the plan in part for a particular stage of the activity, or accept the plan subject to limitations or conditions applying to operations for the activity (subregulations 10(5) and (6)).

 

If the titleholder resubmits the plan by the date referred to in the notice, or a later date agreed with the Regulator, the Regulator has 30 days after receiving the plan to decide whether or not it is reasonably satisfied that the resubmitted plan meets the acceptance criteria that are set out in regulation 10A. Alternatively, if the Regulator is unable to make a decision within 30 days, the Regulator is required to give the titleholder notice in writing to this effect, and set out a proposed timetable for consideration of the plan.

 

Again, subregulation 10(7) makes it clear that a decision by the Regulator in relation to the plan is not invalid only because the Regulator did not meet the 30 day period to make a decision. This ensures that the validity of all decisions is maintained.

 

If the Regulator is reasonably satisfied that the resubmitted plan meets the acceptance criteria in regulation 10A, the Regulator must accept the plan. On the other hand, if the Regulator is not reasonably satisfied that the resubmitted plan meets the criteria, it must do one of the following:

·         Give the titleholder a further notice under subregulation 10(2). Again, the notice would set out the criteria about which the Regulator is not reasonably satisfied, and set a date by which the titleholder may resubmit the plan. The Regulator may use this option to give a titleholder a reasonable number of opportunities to modify and resubmit the plan, as considered appropriate by the Regulator, rather than one of the options below.

·         Refuse to accept the plan.

·         Accept the plan in part for a particular stage of the activity, or accept the plan subject to limitations or conditions apply to operations for the activity.

 

Regulation 10A – Criteria for acceptance of environment plan

Regulation 10A sets out the criteria for acceptance of an environment plan. With the exception of the matters discussed below, the criteria are unchanged in substance from the criteria previously listed in subregulation 11(1) of the Principal Regulations.

 

The words ‘or proposed use’ have been removed in paragraph (a), so that the applicable acceptance criteria is that the environment plan is appropriate for the nature and scale of the activity. As all environment plans are ‘for an activity’, including use or operation of a static structure or item of plant, such as a production facility or pipeline, it is not necessary to also refer to ‘proposed use’.

 

Paragraph (d) has been amended to refer to environmental performance outcomes rather than environmental performance objectives – see items 10 and 11. Where the environment plan relates to an activity that is, or is part of, an offshore project, the appropriateness of environmental performance outcomes will be assessed, among other things, in the context of the environmental performance outcomes for the project set out in the accepted offshore project proposal. It is understood that the outcomes may be refined as further details about the activity are determined; however if the outcomes defined in the environment plan would appear to provide for a reduced level of environmental protection compared to the outcomes defined in the offshore project proposal, the titleholder would be expected to provide justification for the change. The outcomes will still also need to demonstrate that environmental impacts and risks will be managed to an acceptable level.

 

Finally, a new acceptance criterion has been inserted, to provide that a plan cannot be accepted if the activity, or any part of the activity, would be conducted in any part of a declared World Heritage property (within the meaning of the EPBC Act).

 

The Australian Government has committed through international agreements that it will not allow mineral exploration or exploitation activities to be undertaken within the boundaries of a declared World Heritage property. The prohibition applies even if the Regulator is reasonably satisfied that the plan meets the other acceptance criteria in regulation 10A.

 

The prohibition does not apply in relation to environment plans for activities to be carried out outside of, but proximate to, a World Heritage property; plans for these activities must be accepted if the Regulator is reasonably satisfied that the plan meets the acceptance criteria.

 

An exception to this new acceptance criterion provides for measures undertaken to monitor the environment or respond to an emergency. In some cases, there may be a risk that activities carried out outside a declared World Heritage property may have impacts within the property, such as in the case of an escape of petroleum. The exception therefore ensures the protection of declared World Heritage properties by encouraging proactive ongoing environmental (i.e. baseline) monitoring, and by allowing emergency response and monitoring in the event of an emergency (such as oil pollution) within World Heritage properties.

 

With the insertion of this provision, it is not intended to suggest that monitoring or response arrangements should be considered as petroleum or greenhouse gas activities in themselves. Rather, they are means of managing the environmental impacts of actions that are petroleum or greenhouse gas activities. Conversely, it is not intended to suggest that an activity (for example, a seismic survey) would be regarded as not falling within the term ‘petroleum activity’ or ‘greenhouse gas activity’ merely because it constituted a monitoring or response arrangement.

 

Regulation 11 – Notice of decision on environment plan and submission of summary

With the exception of the matters discussed below, new regulation 11 provides in substance for the matters currently provided for in subregulations 11(5) to (8) of the Principal Regulations.

 

Paragraph 11(6)(c) of the Principal Regulations previously provided that notice of a decision to refuse to accept an environment plan, or to accept a plan subject to limitations or conditions, must include a statement of the right of reconsideration or review of the decision under section 434 of the OPGGS Act, if the activity to which the plan relates is to be carried out in the offshore area of a Territory. However, the right to reconsideration or review of a decision was amended by the Offshore Petroleum and Greenhouse Gas Storage Amendment (National Regulator) Act 2011, such that review of a decision by the Administrative Appeals Tribunal is available under the OPGGS Act only in relation to certain matters relating to the release of technical information by the responsible Commonwealth Minister or the titleholder, and not in relation to decisions made under the Regulations. Reference to the right to reconsideration or review of a decision has therefore been repealed by this item. 

 

New subregulation 11(3) makes it clear that the requirement to submit a summary of the accepted environment plan applies, whether the plan is accepted in full, in part or subject to the imposition of limitations or conditions.

 

New subregulation 11(4) sets out the content requirements for an environment plan summary, with some amendments to clarify and strengthen the content requirements as currently set out in subregulation 11(8) of the Principal Regulations.

 

Previously, subparagraph 11(8)(a)(i) provided that an environment plan summary must include coordinates of the activity. However, this could limit flexibility for strategically scoped environment plans. New subparagraph 11(4)(a)(i) therefore requires a summary to include the location of the activity, rather than the specific coordinates of the activity. However, the location description in the summary must be detailed enough to inform the reader of where the activity is to take place, rather than a broad regional description.

 

For consistency of terminology within the Regulations, subparagraph 11(4)(a)(iii) refers to a description of the activity, rather than a description of the action (amending subparagraph 11(8)(a)(iii) of the Principal Regulations). For the same reason, subparagraph 11(4)(a)(iv) refers to details of environmental impacts and risks, rather than details of major environmental hazards and controls (amending subparagraph 11(8)(a)(iv)), and subparagraph 11(4)(a)(v) refers to a summary of the control measures for the activity, rather than a summary of the management approach (amending subparagraph 11(8)(a)(v)).

 

In addition, the content requirements for an environment plan summary in former subregulation 11(8) of the Principal Regulations did not include publication of information on arrangements for on-going monitoring of the titleholder’s environmental performance, as set out in the environment plan, or proposed oil pollution response arrangements, leading to a lack of transparency in relation to these matters. The Regulation therefore inserts new subparagraphs 11(4)(vi) and (vii), to require the environment plan summary to also include:

·         A summary of the arrangements for ongoing monitoring of the titleholder’s environmental performance, and

·         A summary of the response arrangements in the oil pollution emergency plan.

 

As for former subregulation 11(8), an environment plan summary is required to be to the satisfaction of the Regulator. If the details in the environment plan summary are not to the satisfaction of the Regulator, the titleholder is required to submit a revised summary to the Regulator.

 

Under Division 2 of Part 9.6A of the OPGGS Act, if an obligation is imposed on a titleholder, and there are two or more registered holders of the same title, the obligation is imposed on each of the registered holders, but can be discharged by any one of them. Therefore, the obligation in subregulation 11(3) to submit an environment plan summary is met if any one of the registered holders of the title submits the summary.

 

Item [43] – Subregulation 11A(1)

 

This item removes the reference to the ‘operator’ in subregulation 11A(1) of the Principal Regulations and replaces it with a reference to the ‘titleholder’, so that a titleholder is required to consult with the relevant persons mentioned in that subregulation during development of an environment plan or a revision of an environment plan. The concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance with the Regulations – see item 24.

 


 

Item [44] – Paragraph 13(1)(b)

 

This item removes the words ‘or other structure’ in paragraph 13(1)(b) of the Principal Regulations, so that the paragraph requires an environment plan to contain details of the construction and layout of any facility. ‘Facility’ is defined in regulation 4 to include a structure or installation of any kind. It is therefore superfluous to require details of the construction and layout of any facility ‘or other structure’ in paragraph 13(1)(b).

 

Item [45] – At the end of subregulation 13(1)

 

This item adds a note at the end of subregulation 13(1) of the Principal Regulations to remind the reader that an environment plan cannot be accepted by the Regulator if an activity or part of an activity, other than arrangements for environmental monitoring or for responding to an emergency, will be undertaken in any part of a declared World Heritage property – see new regulation 10A (item 42).

 

Item [46] – Paragraph 13(2)(a)

 

Paragraph 13(2)(a) of the Principal Regulations previously required an environment plan to “describe the existing environment that may be affected by the activity, as well as any relevant cultural, social and economic aspect of the environment that may be affected”. However, the definition of ‘environment’ in regulation 4 already includes social, economic and cultural features.

 

The reference to “as well as any relevant cultural, social and economic aspect of the environment that may be affected” is therefore superfluous and has been removed by this item.

 

This does not, however, remove the requirement for titleholders to describe relevant cultural, social and economic features of the environment that may be affected by an activity in an environment plan, and to consider those features when detailing, evaluating and describing the proposed management of the environmental impacts and risks of the activity.

 

Item [47] – At the end of subregulation 13(2)

 

This item adds a note at the end of subregulation 13(2) of the Principal Regulations to remind the reader that the definition of ‘environment’ for the purposes of the Regulations includes any relevant cultural, social and economic aspects of the environment – see regulation 4. See also item 46.

 

Item [48] – Subregulations 13(3) to (5)

 

This item repeals subregulations 13(3) to (5) in the Principal Regulations, and substitutes new subregulations 13(3) to (7).

 

Subregulation 13(3)

Subregulation 13(3) makes it clear that where an activity may affect one or more of the matters of national environmental significance listed in that subregulation, the environment plan must include relevant details. Potential impacts on a matter of national environmental significance, and the measures detailed in the environment plan to reduce those impacts to as low as reasonably practicable and an acceptable level, would be taken into account by the Regulator when deciding whether to accept an environment plan.

 

Subregulation 13(4)

Subregulation 13(4) is largely equivalent to previous subregulation 13(5) in the Principal Regulations, but makes it clear that the description of requirements that apply to the activity and are relevant to the environmental management of the activity must include a description of relevant legislative requirements.

 

The subregulation also requires the environment plan to describe how those requirements will be met. This is of particular importance in the context of streamlining of environmental approvals under the EPBC Act and the OPGGS Act, as the Regulations must provide for the Regulator to be able to assess that the titleholder has made adequate arrangements to ensure all of its environmental obligations will be met.

 

Subregulation 13(5)

Subregulation 13(5) includes the requirements previously in subregulation 13(3) of the Principal Regulations. However, new paragraph 13(5)(b) makes clear that the evaluation of all impacts and risks for the activity should be appropriate to the nature and scale of each impact and risk. It is not intended that, for relatively minor impacts and risks, substantially detailed evaluation should be provided. The level of detail should be appropriate to the type, severity and likelihood of the risk. If a number of the impacts and risks identified in the plan are relatively minor, these could be evaluated in a consolidated manner.

 

The item also inserts a new paragraph 13(5)(c), to require an environment plan to include details of the control measures that will be used to reduce the impacts and risks of the activity to as low as reasonably practicable and an acceptable level. Together with new paragraph 13(7)(a), this clarifies the link between control measures and environmental performance standards (see further detail below).

 

Subregulation 13(6)

Subject to two exceptions, subregulation 13(6) would be equivalent to former subregulation 13(3A) in the Principal Regulations.

 

Subregulation 13(3) of the Principal Regulations previously provided that an environment plan must include an evaluation of all the impacts and risks for an activity. Subregulation 13(3A) provided that, for the avoidance of doubt, that evaluation must evaluate all the significant impacts and risks arising directly or indirectly from all operations of the activity, including construction, and potential emergency conditions, whether resulting from accident or any other reason.

 

The word ‘significant’ in subregulation 13(3A) created confusion and led some operators to interpret that, on the basis of this provision, only the significant impacts and risks of an activity are required to be discussed and evaluated in an environment plan. However it is the policy intention that all impacts and risks of an activity must be identified and evaluated in the plan, as indicated by the word ‘all’ in former paragraph 13(3)(b) (which is new paragraph 13(5)(b)). New subregulation 13(6) therefore clarifies the operation of the provision by removing the word ‘significant’.

 

New paragraph 13(6)(a) also removes the words ‘including construction’ currently in paragraph 13(3A)(a) of the Principal Regulations. The inclusion of these words has also created some confusion, and is not necessary to meet the policy intent of this provision.

 

Subregulation 13(7)

Subregulation 13(7) clarifies former subregulation 13(4) of the Principal Regulations.

 

The reference to legislative requirements in current paragraph 13(4)(a) has been removed, as the requirement to address legislative and other requirements has been incorporated in new subregulation 13(4).

 

New paragraph 13(7)(a) clarifies the link between environmental performance standards and control measures. Generally, environmental performance standards were previously interpreted as referencing pieces of legislation or internal procedures in the environment plan. It is likely that the structure of former subregulation 13(4) contributed to this incorrect interpretation. New paragraph 13(7)(a) specifically requires environmental performance standards to be set for the control measures identified under new paragraph 13(5)(c).

 

This amendment is supported by the insertion of a new definition of ‘control measure’ (see item 6) and an amended definition of ‘environmental performance standard’ (see item 12).

 

New paragraph 13(7)(b) requires the environment plan to define environmental performance outcomes – see items 10 and 11.

 

New paragraph 13(7)(c) ensures there is a clear link between measurement criteria and monitoring of environmental performance outcomes and standards, and clarify that measurement criteria should be provided to ensure each outcome and standard will be met while undertaking the activity.

 

Item [49] – Subregulations 14(2) and (3)

 

This item repeals subregulations 14(2) and (3) in the Principal Regulations, and substitutes new subregulations 14(2) and (3).

 

Subregulation 14(2)

Former subregulation 14(2) of the Principal Regulations provided that the implementation strategy must include measures to ensure that the environmental performance objectives and standards in the environment plan are met. This duplicated both the former and new requirements in proposed subregulation 14(3), and therefore subregulation 14(2) is repealed by this item.

 

New subregulation 14(2) in part replaces subregulation 15(1) in the Principal Regulations (which has been repealed by item 53), which requires an environment plan to include arrangements for, among other things, reporting information about an activity to the Regulator, no less than annually, that is sufficient to enable the Regulator to determine whether the environmental performance objectives and standards in the plan are met.

 

The Principal Regulations did not previously contain a clear, stand-alone requirement for titleholders to report their environmental performance against the environment plan, which would reinforce the requirement for regular submission of reports. The new Regulation therefore inserts a new standalone requirement for regular reporting against the environmental performance outcomes and standards set out in the environment plan in the Principal Regulations – see item 82.

 

New subregulation 14(2) requires the implementation strategy of an environment plan to provide for the timing of reports to the Regulator in accordance with the new standalone reporting requirement. This enables the Regulator to approve the proposed frequency of reporting through the environment plan assessment and acceptance process. The reporting frequency set out in the environment plan must be no less than annually.

 

Subregulation 14(3)

New subregulation 14(3) largely reflects the requirements in former subregulation 14(3) of the Principal Regulations. However, new subregulation 14(3) makes it clear that the implementation strategy is an operational document that is used to ensure that all of the environmental impacts and risks for an activity will be continually identified and reduced to a level that is as low as reasonably practicable, and that the environmental performance outcomes and standards set out in the plan are met, for the duration of the activity.

 

Subregulation 14(3) requires the implementation strategy to contain a description of the ‘environmental management system’ for the activity. A definition of ‘environmental management system’ is also inserted by the Regulation – see item 8.

 

Paragraph 14(3)(b) requires a description of measures to be used to ensure that the control measures detailed in the environment plan (as required by paragraph 13(5)(c) – see item 48) are effective in reducing the environmental impacts and risks of the activity to as low as reasonably practicable and an acceptable level. This further emphasises the link between environmental performance standards and control measures in an environment plan – see further discussion under item 48.

 

Item [50] – At the end of subregulation 14(4)

 

This item clarifies that it is the intent that the requirement in subregulation 14(4) is applicable both in relation to normal operations and emergencies or potential emergencies.

 

Item [51] – Subregulation 14(5)

 

This item clarifies that it is the intent that the requirement in subregulation 14(5) is applicable both in relation to normal operations and emergencies or potential emergencies.

 

Item [52] – Subregulations 14(6) to (8A)

 

This item repeals subregulations 14(6) to (8A) in the Principal Regulations, and substitutes new subregulations 14(6) to (8E).

 

Subregulation 14(6)

New subregulation 14(6) reflects the requirements in former subregulation 14(6) of the Principal Regulations. However, new subregulation 14(6) makes it clear that the arrangements for monitoring, audit, management of non-conformance and review of the titleholder’s environmental performance and the implementation strategy must be sufficient to enable the Regulator and the titleholder to determine that the titleholder’s  environmental performance is consistent with the environmental performance outcomes detailed in the environment plan, and to ensure that environmental performance standards for control measures are being met.

 

Previously, the Principal Regulations did not clearly require titleholders to demonstrate how monitoring arrangements provided for in the implementation strategy will be suitable to account for the particular risks and impacts to the environment in which the activity is being undertaken. There was therefore limited capacity for the Regulator to ensure that appropriate monitoring arrangements were included in the implementation strategy. It is not the policy intent to include specific monitoring requirements in the Regulations, given the objective-based nature of the Regulations; monitoring arrangements should be appropriate to the impacts and risks of a particular activity.

 

Including a specific link to environmental performance outcomes and environmental performance standards in subregulation 14(6) ensures that monitoring arrangements are commensurate with the level of risk and impact of an activity, as environmental performance outcomes and standards are identified in the context of the risks and impacts of the activity.

 

In addition, new subregulation 14(6) also inserts a specific requirement to provide for sufficient recording of the titleholder’s environmental performance and the implementation strategy, in addition to the pre-existing requirements of subregulation 14(6). This is as a result of the repeal of subregulation 15(1) (see item 53), which required, among other things, an environment plan to include arrangements for recording information about an activity sufficient to enable the Regulator to determine whether the environmental performance objectives and standards in the environment plan are met.

 

New subregulation 14(6) also replaces a reference to an ‘operator’ with a reference to the ‘titleholder’. The concept of an ‘operator’ has been removed from the Principal Regulations, and the titleholder made responsible for compliance – see item 24.

 

Subregulation 14(7)

New subregulation 14(7) is largely equivalent to current subregulation 14(7) in the Principal Regulations, but makes it clear that the implementation strategy must provide for sufficient monitoring of emissions and discharges, in addition to the development and maintenance of a quantitative record of emissions and discharges.

 

Data obtained through monitoring of emissions and discharges would be included in the record, which should be sufficient to enable an assessment of whether the environmental performance outcomes and environmental performance standards in the environment plan are being met. By also requiring that the arrangements for monitoring and maintenance of a record of emissions and discharges must be sufficient to enable an assessment of those outcomes and standards, the Regulator will be able to assess the proposed monitoring arrangements to determine whether they are appropriate in the context of the environmental impacts and risks of the particular activity.

 

The expansion of subregulation 14(7) to also include monitoring, and ensure that monitoring is sufficient to assess performance against environmental performance outcomes and standards, alsos ensure that, with the repeal of Division 4.1 of the Principal Regulations, which relates specifically to the management of petroleum discharged in produced formation water (see item 91), all discharges and emissions, including produced formation water, are required to be monitored and assessed against the environment performance outcomes and standards in the environment plan. This ensures that the impacts and risks of discharges of produced formation water will be as low as reasonably practicable and of an acceptable level.

 

Subregulation 14(8)

Subregulation 14(8) is largely equivalent to current subregulation 14(8) in the Principal Regulations, but re-names the ‘oil spill contingency plan’, which is instead called an ‘oil pollution emergency plan’. This ensures the terminology is consistent with Article 3 of the International Convention on Oil Pollution Preparedness, Response and Cooperation 1990.

 

Subregulation 14(8AA)

The Regulation substitutes new subregulation 14(8AA) in place of the former subregulation 14(8AA) in the Principal Regulations, to clarify the information required in an oil pollution emergency plan. This assists titleholders to understand the requirements for oil pollution emergency plans, and better enable the Regulator to determine the appropriateness of oil spill preparedness and response arrangements. The new subregulation largely formalises current practice, as it largely reflects the information that has been provided to date in oil spill contingency plans.

 

New subregulation 14(8AA) requires an oil pollution emergency plan to contain adequate arrangements for responding to and monitoring oil pollution. The use of the word ‘adequate’ is to ensure that, in assessing an oil pollution emergency plan as part of an environment plan, it is clear that the Regulator will consider the adequacy of the arrangements proposed in the oil pollution emergency plan in deciding whether to accept or refuse to accept the overall environment plan.

 

In the event of an oil spill, environmental monitoring is important in order to inform necessary response activities. There are no prescriptive requirements in the Regulations for how or what environmental monitoring should be undertaken during emergency conditions, given the range of potential emergency situations that may occur, and the varied level of impacts and risks of those situations. However, it is appropriate that titleholders detail proposed environmental monitoring arrangements in an oil pollution emergency plan, to enable the Regulator to assess the adequacy and appropriateness of the proposed arrangements with respect to the particular activities covered by the plan.

 

Subregulation 14(8A)

New subregulation 14(8A) clarifies that the arrangements for testing of response arrangements in the oil pollution emergency plan, which are required to be set out in the implementation strategy, should be appropriate to the particular response arrangements, and to the nature and scale of oil pollution for the activity.

 

This amendment assists in addressing inconsistency in the level of testing that has been undertaken – see also new subregulation 14(8B) (discussed below).

 

Subregulation 14(8B)

New subregulation 14(8B) clarifies the requirements for testing of the response arrangements in an oil pollution emergency plan. The requirement to test response arrangements previously in subregulation 14(8A) of the Principal Regulations only stated when testing is to occur; it did not adequately address the requirements of testing. This resulted in inconsistency in the level of testing being undertaken by operators.

 

In addition to a proposed schedule of tests, subregulation 14(8B) requires the arrangements for testing of response arrangements to set out the objectives of testing, and include mechanisms to examine the effectiveness of response arrangements against those objectives and to address recommendations arising from the tests. This ensures that response capability is effectively tested and requires the titleholder to demonstrate they are adequately prepared to respond to a spill and mitigate the impacts of a spill.

 

Subregulation 14(8C)

New subregulation 14(8C) sets out the requirements for the proposed schedule of tests. The criteria for frequency of testing are unchanged in substance from the requirements currently listed in subregulation 14(8A) of the Principal Regulations.

 

Subregulation 14(8D)

New subregulation 14(8D) requires the implementation strategy to provide for monitoring of impacts to the environment from oil pollution and activities undertaken in response to oil pollution, appropriate to the nature and scale of the risk of environmental impacts for the activity. The arrangements for monitoring should also inform any remediation activities that will be required to be undertaken as a result of oil pollution.

 

In the event of oil pollution, environmental monitoring is important in order to assess the impacts to the environment of the spill and the efficacy of response or remediation measures, and to inform remediation activities that will be required to be undertaken. Requiring the implementation strategy to provide for appropriate monitoring also supports section 572A of the OPGGS Act, which applies in the event of an escape of petroleum to require a titleholder, among other things, to clean up the escaped petroleum, carry out environmental monitoring of the impact of the escape on the environment, and remediate any resulting damage to the environment.

 

Subregulation 14(8E)

New subregulation 14(8E) specifies a requirement for a titleholder to include in the implementation strategy information demonstrating that proposed response arrangements in the oil pollution emergency plan are consistent with the national system for oil pollution preparedness and response.

 

Item [53] – Regulation 15

 

This item repeals regulation 15 of the Principal Regulations, and inserts a new regulation 15.

 

Previously, subregulation 15(1) required an environment plan to include arrangements for recording, monitoring and reporting information about an activity, sufficient to enable the Regulator to determine whether the environmental performance objectives and standards in the environment plan were met. The requirements for ongoing monitoring and recording are now incorporated into subregulations 14(6) and (7) by the Regulation – see item 52. A new standalone requirement for regular reporting of environmental performance to the Regulator has also been inserted by the Regulation – see item 84 (new regulation 26C).

 

Subregulation 15(2) previously required an environment plan to include arrangements for the operator to notify the Department of the responsible State or Northern Territory Minister before the proposed date of commencement of drilling operations or seismic survey operations in certain circumstances. This has been replaced by a new standalone offence provision – see item 91 (new regulation 30).

 

New regulation 15 requires an environment plan to include the name and contact details of the titleholder and a liaison person for the activity. If there is more than one registered holder of a single title, all of the registered holders collectively are the ‘titleholder’, and therefore the requirement to include contact details of the titleholder would apply to all of them. In the case of a petroleum titleholder, contact details should already have been provided to NOPSEMA under section 286A of the OPGGS Act. As a result of the application of new regulation 31 (see item 91), the titleholder could elect to refer to the information that was previously given under that section, rather than providing the information again.

 

The liaison person would be the person whose details will be published on the Regulator’s website on submission of an environment plan (subsection 9(8) – see item 42) or a proposed revision of an environment plan (regulation 20A – see item 59), and in the environment plan summary (subsection 11(4) – see item 42). The Regulator may also contact this person in relation to the activity/environment plan. 

 

New regulation 15 srequire the following details to be provided, if any:

·         Telephone number

·         Fax number

·         Email address

 

The words ‘if any’ does not mean that the information is voluntary. The effect of the provision is, for example, that if a titleholder has a telephone number and email address, but does not have a fax number, details of the telephone number and email address must be included in the environment plan, but the titleholder would not fail to meet the requirement because it did not provide a fax number.

 

To ensure the Regulator has current details of the titleholder and the titleholder’s nominated liaison person, regulation 15 also requires the environment plan to include arrangements for notifying the Regulator of a change in the titleholder, a change in the titleholder’s nominated liaison person, or a change in the contact details for either the titleholder or the liaison person.

 

Item [54] – Regulation 17

 

This item repeals regulation 17 in the Principal Regulations and replaces it with a new regulation 17.

 

The new regulation 17 provides that a titleholder, rather than an operator, must submit a proposed revision of an environment plan in the circumstances provided for in that regulation. This is to reflect the removal of the concept of an ‘operator’ from the Regulations, and transfer of responsibility for compliance with the Regulations to the titleholder – see items 24 and 36-40.

 

Former subregulation 17(1) in the Principal Regulations is separated into two new subregulations – subregulations 17(1) and (5).

 

New subregulation 17(5) continues to require submission of a proposed revision of an environment plan before the commencement of any new stage of an activity, or any significant modification of an activity, that is not provided for in the environment plan currently in force for the activity.

 

New subregulation 17(1) now requires the Regulator’s approval to submit a proposed revision of an environment plan before the commencement of a new activity. If a titleholder proposes to undertake a new activity, they have two options: submit a new environment plan or submit a proposed revision of an existing environment plan. It is intended that a titleholder could use the latter option in cases where there is a connection between the activity or activities in the existing environment plan and the new activity. In other cases, it may be more appropriate for the titleholder to submit a new environment plan.

 

It is not anticipated that a formal process would be required for approval. For example, the titleholder could agree with the Regulator whether a proposed revision of an environment plan may be submitted for a new activity prior to preparing the revision.

 

New subregulation 17(2) enables a titleholder to submit a proposed revision of an environment plan for a new activity that is, or is part of, an offshore project (as defined in regulation 4 – see item 23) only if:

·         The Regulator has accepted an offshore project that proposal that includes that new activity; or

·         The Environment Minister has approved the taking of an action that is equivalent to or includes the activity under Part 9 of the EPBC Act; or

·         The Environment Minister has made a decision that an action that is equivalent to or includes the activity is not a controlled action (section 75 of the EPBC Act) or is not a controlled action if undertaken in a particular manner (section 77A of the EPBC Act).

 

New subregulation 17(3) provides that if a titleholder submits a proposed revision of an environment plan for a new activity that is, or is part of, an offshore project, and none of the circumstances listed above applies, the revision is taken not to have been submitted. In effect, this means that the proposed revision cannot be considered by the Regulator, and the assessment and acceptance process in regulations 9A to 11 will not apply.

 

As the proposed revision is taken not to have been submitted, environment plan levy would not be imposed.

 

It is an offence for a titleholder to undertake an activity without an environment plan in force for the activity (subregulation 6(1) – see item 36). Therefore, if the titleholder wishes to undertake the new activity that is, or is part of, an offshore project, it will need to develop, submit, publicly consult on and obtain the Regulator’s acceptance of an offshore project proposal that includes that activity. It is intended that an offshore project proposal would only need to be developed for that particular activity. Therefore if the activity were part of a broader development for which an offshore project proposal had been accepted, but the particular activity had not been included in the original proposal, it is not intended that the titleholder would need to re-do the original proposal for all activities, including the new activity.

 

Importantly, proposed revisions of existing environment plans that are submitted for a reason other than a new activity may be submitted and will be assessed by the Regulator, even if the activity or activities to which the existing plan relates are, or are part of, an offshore project. This includes proposed revisions of existing environment plans that are submitted for a new stage of an activity. This ensures that a titleholder does not have to develop, submit and consult on an offshore project proposal for activities already covered by an environment plan that was accepted prior to the commencement of the Regulation.

 

In addition, if a titleholder submits a proposed revision of an environment plan that was accepted prior to the commencement of the Regulation, and the proposed revision includes a new activity that is, or that is part of, an offshore project, it is only the new activity that will require an offshore project proposal or a relevant decision by the Environment Minister, even if the activities in the previously accepted plan are, or are part of, an offshore project.

 

See also the discussion about offshore project proposals, and the policy rationale for requiring an offshore project proposal for offshore projects, under item 35.

 

Subregulations 17(2) and (3) do not apply to activities that are not, or are not part of, an offshore project, even if an offshore project proposal had been voluntarily prepared and submitted by the proponent in relation to that activity – see item 35 (regulation 5F).

 

Under section 146D of the EPBC Act, an approval by the Environment Minister under section 146B of that Act (approval of an action taken in accordance with an endorsed policy, plan or program) is taken to be an approval of the taking of that action under Part 9 of that Act.

 

However, subregulation 17(4) specifies that, for the purposes of subparagraph 17(2)(b)(iii), an approval by the Environment Minister under section 146B of the EPBC Act would not be taken to be an approval of the taking of an action under Part 9 of that Act. Classes of actions approved under section 146B of the EPBC Act do not exempt proposed actions under the Principal Regulations from preparing and submitting an offshore project proposal for assessment and acceptance. Activities that are, or are part of, an offshore project would themselves be approved under section 146B of the EPBC Act if the Regulator accepts an offshore project proposal that includes the activity, and subsequently accepts an environment plan that relates to the activity, under the Principal Regulations.

 

Subregulation 17(6) is equivalent to former paragraphs 17(2)(b) and (c) in the Principal Regulations.

 

Subregulation 17(7) amends the requirement in current paragraph 17(2)(a) of the Principal Regulations to require that if there is a change in the titleholder that will result in a change in the manner in which the environmental impacts and risks of an activity will be managed, the new titleholder must submit a proposed revision of the environment plan as soon as practicable. It is not intended to require a proposed revision every time there is a change in the membership of the titleholder group. If this were the case, a titleholder would be required to submit a proposed revision for every change in title, including transfers of relatively minor title interests that have no impact on the management of environmental impacts and risks. This would create an unnecessary burden on industry for no corresponding increase in environmental standards. 

 

Under regulation 7, a titleholder commits an offence if it undertakes an activity in a manner contrary to the environment plan in force for the activity (see item 37). If a change in titleholder will result in a change to the manner in which environmental impacts and risks will be managed, the titleholder will need to ensure it submits a proposed revision in accordance with subregulation 17(7) to avoid contravening regulation 7. 

 

Subregulation 17(8) to (11) provide for transitional arrangements for situations in which titleholders that become responsible for environment plans previously developed and submitted by operators want to change the manner in which the environmental impacts and risks of the activity are managed from the way in which they are managed under the inherited plan.

 

As noted above, under regulation 7 a titleholder commits an offence if it undertakes an activity in a manner contrary to the environment plan in force for the activity (see item 37). If a titleholder proposes to change the manner in which environmental impacts and risks will be managed from the way they are managed in an inherited environment plan, the titleholder would need to submit a proposed revision in accordance with subregulation 17(9) or (11) to avoid potentially contravening regulation 7. These transitional provisions are required as no other provision in regulation 17 apply to enable or require a titleholder to submit a proposed revision if they want to change the manner in which environmental impacts and risks are managed, unless there is also a change in titleholder (subregulation 17(7)).    

 

A new regulation 43 (inserted by item 98) provides that any environment plan in force immediately before 28 February 2014 would continue to be an environment plan in force under the amended Regulations. Subregulations 17(8) and (9) require a proposed revision of the plan to be submitted by no later than 31 August 2014 (six months after commencement of the amendments) if the titleholder proposes to change the manner in which the environmental impacts and risks of the activity will be managed from the way they are managed in the environment plan that is continued in force by new regulation 43.

 

A new regulation 44 (inserted by item 98) provides that if the operator submitted an environment plan or proposed revision prior to commencement of the amendments, the plan or proposed revision is taken to have been submitted by the titleholder on the date that it was submitted by the operator. If the plan or proposed revision is subsequently accepted by the Regulator, and the titleholder proposes to change the manner in which the activities are managed under the plan, the titleholder is required to submit a revision of the plan within six months from the day on which the Regulator notified the titleholder of the acceptance of the plan.

 

The titleholder also has the option to withdraw the plan before the Regulator makes a decision to accept or refuse to accept the plan under subregulation 9(9) – see item 42. However, the transitional provision applies in circumstances where the titleholder has not done so, whether because the decision is made shortly after commencement of the amendments, the titleholder has not had the opportunity to consider the plan before an acceptance decision is made, or some other reason.   

 


 

Item [55] – Subregulation 18(1)

 

This item amends subregulation 18(1) of the Principal Regulations to provide that the titleholder, rather than the operator, must submit a proposed revision of an environment plan to the Regulator if the Regulator requests the titleholder to do so. This is to reflect the removal of the concept of an ‘operator’ from the Regulations, and transfer of responsibility for compliance with the Regulations to the titleholder – see item 24.

 

Item [56] – Subregulation 18(8)

 

This item amends subregulation 18(8) of the Principal Regulations to provide that the titleholder, rather than the operator, must submit a proposed revision of an environment plan that was continued in force under regulation 40 (following previous amendments to the Regulations in 2012) to the Regulator if the Regulator requests the titleholder to do so. This is to reflect the removal of the concept of an ‘operator’ from the Regulations, and transfer of responsibility for compliance with the Regulations to the titleholder – see item 24. The reference in subregulation 18(8) to ‘the titleholder for the activity’ is simply a reference to the titleholder.

 

Item [57] – Subregulation 19(1)

 

This item amends subregulation 19(1) of the Principal Regulations to provide that a titleholder, rather than an operator, must submit a proposed revision of an environment plan to the Regulator at least 14 days before the end of each period of 5 years, commencing on the latest of the days mentioned in that subregulation. This is to reflect the removal of the concept of an ‘operator’ from the Regulations, and transfer of responsibility for compliance with the Regulations to the titleholder – see item 24.

 

Item [58] – Paragraph 19(1)(c)

 

This item corrects a typographical error in the Principal Regulations.

 

Item [59] – After regulation 20

 

In order to improve transparency in relation to activities and proposed activities, this item inserts a new regulation 20A to require the Regulator to publish certain information on its website as soon as practicable after a proposed revision of an environment plan is submitted to the Regulator. This will inform the public about the receipt of the proposed revision, the reason for the revision, and provide high level information about the activity to which the revised plan relates.

 

Unlike publication of an offshore project proposal under regulation 5C (see item 35), publication of the information about a revised environment plan would not be an invitation for public comment. The information would be published to inform the public about proposed activities, and the status of the proposed revision (e.g. whether the Regulator has accepted or refused to accept the proposed revision). In order to have a revised environment plan accepted, titleholders are required under regulation 11A to consult with relevant persons during the development of a revision of an environment plan.

 

It is required to publish revised environment plans in full; plans contain commercially sensitive information, and may be quite detailed and technically complex.

 

If there is more than one registered holder of a title under the authority of which the activity to which a plan relates is to be carried out, the name of each of the registered holders of the title would be published under paragraph 20A(a).

 

The description of the activity or stage of the activity under paragraph 20A(b) would be quite high level and detail the broad activity type.

 

Item [60] – Regulation 21

 

This item ensures that new regulation 9A, 10 and 10A (see item 42), in addition to regulations 11 and 11A, apply to proposed revisions of environment plans.

 

Item [61] – Regulation 21 (note)

 

This item amends the note to regulation 21 to remove references to specific regulation numbers to reflect the change made by item 60.

 

Item [62] – Subregulation 23(1)

 

This item omits the reference to an ‘operator’ in subregulation 23(1) of the Principal Regulations and replace it with a reference to the ‘titleholder’. The concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance – see item 24. The reference to ‘the titleholder for the activity’ is simply a reference to the titleholder.

 

Item [63] – Subregulation 23(1)

 

This item omits the words ‘in force’ in subregulation 23(1) to make clear that withdrawal of acceptance of an environment plan would not replace the current version of the plan with a previous version (if any), but would result in no plan being in force for the activity.

 

Item [64] – Paragraph 23(2)(a)

 

This item ensures that the Regulator may withdraw acceptance of an environment plan in force for an activity on the ground that the titleholder has not complied with certain specified requirements under the OPGGS Act. The reference to an ‘operator’ has been removed, as the concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance – see item 24.

 

The reference to ‘instrument holder’ has been replaced with the reference to ‘titleholder’ for consistency with usage in the OPGGS Act – see items 21 and 33.

 

Item [65] – Subparagraph 23(2)(a)(ii)

 

Previously, the grounds for withdrawal of the acceptance of an environment plan under the Principal Regulations included that the ‘operator or instrument holder’ ( replaced with ‘titleholder’ – see item 64) has not complied with a direction given by the Regulator under section 574 of the OPGGS Act (subparagraph 23(2)(a)(ii)). Section 574 of the OPGGS Act gives NOPSEMA the power to give directions to a petroleum titleholder as to any matter in relation to which regulations may be made.

 

It was not a specified ground for withdrawal of the acceptance of an environment plan, however, if a greenhouse gas titleholder had not complied with a direction given to it by the responsible Commonwealth Minister (who is the Regulator in relation to greenhouse gas activities under the Principal Regulations) under the general power of the Minister in section 580 of the OPGGS Act to give directions to a greenhouse gas titleholder as to any matter in relation to which regulations may be made. The amendment made by this item therefore also makes a failure to comply with a direction given by the Regulator under section 580 a ground for withdrawal of the acceptance of an environment plan.

 

There are also other directions that may be given under the OPGGS Act, the breach of which would appropriately be grounds for withdrawal of the acceptance of an environment plan. These are:

·         A significant incident direction that may be given by NOPSEMA to a petroleum titleholder under section 576B in the event of an escape of petroleum;

·         A remedial direction that may be given to a petroleum titleholder by NOPSEMA under regulation 586;

·         A remedial direction that may be given to a greenhouse gas titleholder by the responsible Commonwealth Minister under section 592.

 

This item therefore also makes a failure to comply with any of those directions a ground for withdrawal of the acceptance of an environment plan.

 

Item [66] – At the end of subregulation 23(2)

 

This item inserts an additional ground for the Regulator to withdraw the acceptance of an environment plan for an activity.

 

Item 84 inserts a new standalone requirement for a titleholder to submit regular reports to the Regulator in relation to the titleholder’s environmental performance for an activity – see discussion in relation to that item. This includes the ability for the Regulator to ask the titleholder to modify the report if the Regulator is not reasonably satisfied that a report is sufficient to enable the Regulator to determine whether the environmental performance outcomes and standards in the environment plan have been met.

 

Item 66 makes it a ground for withdrawal of the acceptance of an environment plan if the Regulator is not reasonably satisfied, after two or more requests for modification of a report on environmental performance, that the titleholder has given the Regulator sufficient information to enable it to determine whether the environmental performance outcomes and standards in the environment plan have been met.

 

The Regulator has a range of graduated enforcement mechanisms available to it, and therefore a decision to take the step of withdrawing the acceptance of an environment plan would depend on all the relevant circumstances, such as whether the titleholder has made genuine attempts to comply, or whether the failure to comply has caused the Regulator to be concerned that there may be a risk to the environment from the activity. The Regulator is required to give at least 30 days’ notice of an intention to withdraw the acceptance of an environment plan, and give the titleholder or any other person to whom a copy of the notice has been given an opportunity to submit any matters for the Regulator to take into account in finally deciding whether or not to withdraw the acceptance of the plan.

 

Item [67] – Subregulation 23(3)

 

Paragraph 23(3)(b) of the Principal Regulations previously provided that notice of a decision to withdraw the acceptance an environment plan must include a statement of the right of reconsideration or review of the decision under section 434 of the OPGGS Act, if the activity to which the plan relates is carried out in the offshore area of a Territory. However, the right to reconsideration or review of a decision was amended by the Offshore Petroleum and Greenhouse Gas Storage Amendment (National Regulator) Act 2011, such that review of a decision by the Administrative Appeals Tribunal is available under the OPGGS Act only in relation to certain matters relating to the release of technical information by the responsible Commonwealth Minister or the titleholder, and not in relation to decisions made under the Regulations. Reference to the right to reconsideration or review of a decision has therefore been repealed by this item. 

 

Item [68] – Subregulation 24(1)

 

This item omits the words ‘in force’ in subregulation 24(1) to make clear that withdrawal of acceptance of an environment plan would not replace the current version of the plan with a previous version (if any), but would result in no plan being in force for the activity. See also item 63.

 

Item [69] – Paragraph 24(5)(a)

 

This item removes the reference to the ‘operator or instrument holder’ in paragraph 24(5)(a) of the Principal Regulations and replaces it with a reference to the ‘titleholder’, so that the Regulator must take into account any action taken by the titleholder to remove the ground for withdrawal of acceptance of an environment plan, or to prevent the recurrence of that ground, before making a decision to withdraw acceptance of the plan.

 

The reference to an ‘operator’ has been removed, as the concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance – see item 24.

 

The reference to ‘instrument holder’ has been replaced with the reference to ‘titleholder’ for consistency with usage in the OPGGS Act – see items 21 and 33. 

 

Item [70] – Subregulation 25(1)

 

This item omits the words ‘in force’ in subregulation 25(1) to make clear that withdrawal of acceptance of an environment plan would not replace the current version of the plan with a previous version (if any), but would result in no plan being in force for the activity. See also item 63.

 


 

Item [71] – Subregulation 25(1)

 

This item removes the reference to the ‘operator or instrument holder’ in subregulation 25(1) of the Principal Regulations and replaces it with a reference to the ‘titleholder’. Under subregulation 25(1), therefore, the Regulator has the ability to withdraw the acceptance of an environment plan on the ground that the titleholder has failed to comply with a provision of the Act, or a regulation mentioned in paragraph 23(2)(b) of the Regulations, even though the titleholder has been convicted of an offence by reason of the failure to comply with that provision.

 

The reference to an ‘operator’ has been removed, as the concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance – see item 24.

 

The reference to ‘instrument holder’ has been replaced with the reference to ‘titleholder’ for consistency with usage in the OPGGS Act – see items 21 and 33. 

 

Item [72] – Subregulation 25(2)

 

This item in effect removes the reference to ‘the operator of, or the instrument holder for, an activity’ in subregulation 25(2) of the Principal Regulations, and replaces it with a reference to the ‘titleholder’. Under subregulation 25(2), therefore, the titleholder could be convicted of an offence for failure to comply with a provision of the Act, or a regulation mentioned in paragraph 23(2)(b), even though the Regulator has also withdrawn acceptance of the titleholder’s environment plan on the same ground.

 

The reference to an ‘operator’ has been removed, as the concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance – see item 24.

 

The reference to ‘instrument holder’ has been replaced with the reference to ‘titleholder’ for consistency with usage in the OPGGS Act – see items 21 and 33. 

 

Item [73] – At the end of Part 2

 

This item adds a new Division 2.6 (End of environment plan) at the end of Part 2 of the Principal Regulations.

 

Subregulation 25A – Plan ends when titleholder notifies completion

The Principal Regulations referred to an ‘environment plan in force for an activity’; however, there was no mechanism for ceasing an environment plan to be in force once all the activities and obligations under the plan have been completed. This could have unintended consequences, such as continuing liability for payment of environment plan levy, or continuing obligation to submit five year revisions of an environment plan.

 

New regulation 25A specifies that the operation of an environment plan will end when the Regulator accepts a notification from the titleholder that the activity or activities to which the plan relates have ended and all obligations under the environment plan have been completed.

 

As a result of the definition of ‘in force’ inserted by item 20, a plan ceases to be in force when the operation of the plan ends.

 

Item [74] – Subregulation 26(1)

 

This item in effect removes the reference to an ‘operator of an activity’ in subregulation 26(1) and replaces it with a reference to a titleholder, so that a titleholder commits an offence if there is a reportable incident in relation to an activity, and the titleholder does not notify the reportable incident in accordance with subregulation 26(4). This is to reflect the removal of the concept of an ‘operator’ from the Regulations, and transfer of responsibility for compliance with the Regulations to the titleholder – see item 24.  

 

Under Division 2 of Part 9.6A of the OPGGS Act, if an obligation is imposed on a titleholder, and there are two or more registered holders of the same title, the obligation is imposed on each of the registered holders, but can be discharged by any one of them.

 

The penalty for a failure to comply with subregulation 26(1) remains at 40 penalty units, or 200 penalty units for an offence committed by a body corporate due to the operation of subsection 4B(3) of the Crimes Act 1914, and the offence continues to be an offence of strict liability. However, it is the titleholder who is responsible for compliance. It is still appropriate to apply strict liability to the offence to ensure that the regulation can be enforced more effectively as, given the remote and complex nature of offshore operations and the prevalence of multiple titleholder arrangements, it is extremely difficult to prove intent. The intention of the application of strict liability is therefore to improve compliance in the regulatory regime. This is consistent with the principles outlined in A Guide To Framing Commonwealth Offences, Infringement Notices and Enforcement Powers, September 2011, which include that the punishment of offences not involving fault may be appropriate where it is likely to significantly enhance the effectiveness of the enforcement regime in deterring certain conduct. The penalty of 40 penalty units is also consistent with the Guide, which expresses a preference for a maximum of 60 penalty units for offences of strict liability.

 

Item [75] – Paragraph 26(4)(c)

 

This item repeals paragraph 26(4)(c) of the Principal Regulations and substitute a new paragraph 26(4)(c) to require that a notification of a reportable incident under subregulation 26(1) must be oral.

 

Previously, paragraph 26(4)(c) provided that an operator may notify the Regulator of a reportable incident either orally or in writing. In the case of a written notification, there is a risk that the notification may not be received when or soon after it is sent, and therefore the notification may not be actioned promptly or appropriately. The amendment resulting from this item will ensure that all reportable incidents can be addressed in a timely manner by requiring the notification of a reportable incident to be given to the Regulator orally.

 

Following the notification of a reportable incident by the titleholder, a written record of the notification will continue to be required in accordance with subregulation 26(6) (see item 77), and a written report of the incident will also continue to be required in accordance with regulation 26A (see item 78).

 

Item [76] – Subparagraph 26(4)(d)(iii)

 

This item amends subparagraph 26(4)(d)(iii) of the Principal Regulations to require a notification of a reportable incident to include the corrective action that has been taken, or is proposed to be taken, to stop, control or remedy the reportable incident.

 

Subparagraph 26(4)(d)(iii) previously required an operator to include in a notification of a reportable incident the corrective action that has been taken, or is proposed to be taken, to prevent a similar recordable incident. This requirement mixed the concepts of ‘corrective’ and ‘preventive’ actions, leading to potential confusion in relation to the information that is required to be provided.

 

Often, corrective actions taken at the time of an incident are appropriate to stop the immediate cause of the incident, but may not prevent the occurrence of similar incidents in the future. In addition, as a notification under regulation 26 is required no later than two hours after the first occurrence of the incident or after the titleholder first becomes aware of the incident, the titleholder is likely to be devoting its resources to addressing the immediate incident, and will not have had time to consider preventive actions to ensure that a similar incident does not occur again. This item therefore clarifies the information required.

 

Item [77] – At the end of regulation 26

 

This item includes within regulation 26 the requirement that was previously in regulation 26AA of the Principal Regulations, for the titleholder to give a written record of a notification of a reportable incident required under subregulation 26(1), as soon as practicable after the notification, to (a) the Regulator, (b) the Titles Administrator and (c) the Department of the responsible State or Northern Territory Minister. The requirement has been removed from regulation 26AA (which was repealed by item 81) and inserted in regulation 26 so that all requirements relating to notifications of reportable incidents are included within the same regulation.

 

Under Division 2 of Part 9.6A of the OPGGS Act, if an obligation is imposed on a titleholder, and there are two or more registered holders of the same title, the obligation is imposed on each of the registered holders, but can be discharged by any one of them.

 

‘Responsible State Minister’ and ‘responsible Northern Territory Minister’ are defined in section 7 of the OPGGS Act. The responsible State Minister for all States other than Tasmania, and the responsible Northern Territory Minister, is the Minister who is the State or Northern Territory member of the Joint Authority for the relevant State or Northern Territory. The responsible State Minister for Tasmania is the Minister of Tasmania who is responsible for administering the Tasmanian Petroleum Submerged Lands Act.

 

As an example, therefore, if the incident occurred in the offshore area of Western Australia, the titleholder would be required to give a written record of the notification to the Department of the Western Australian Minister who is the State member of the Joint Authority for Western Australia.

 


 

Item [78] – Subregulation 26A(1)

 

This item in effect removes the reference to an ‘operator of an activity’ in subregulation 26A(1) of the Principal Regulations and replaces it with a reference to a ‘titleholder’, so that a titleholder commits an offence if it does not submit a written report of a reportable incident in accordance with subregulation 26A(4). The concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance with the Regulations – see item 24.

 

Under Division 2 of Part 9.6A of the OPGGS Act, if an obligation is imposed on a titleholder, and there are two or more registered holders of the same title, the obligation is imposed on each of the registered holders, but can be discharged by any one of them.

 

The penalty for a failure to comply with subregulation 26A(1) remains at 40 penalty units, or 200 penalty units for an offence committed by a body corporate due to the operation of subsection 4B(3) of the Crimes Act 1914, and the offence continues to be an offence of strict liability. However, it would be the titleholder who is responsible for compliance. It is still appropriate to apply strict liability to the offence to ensure that the regulation can be enforced more effectively as, given the remote and complex nature of offshore operations and the prevalence of multiple titleholder arrangements, it is extremely difficult to prove intent. The intention of the application of strict liability is therefore to improve compliance in the regulatory regime. This is consistent with the principles outlined in A Guide To Framing Commonwealth Offences, Infringement Notices and Enforcement Powers, September 2011, which include that the punishment of offences not involving fault may be appropriate where it is likely to significantly enhance the effectiveness of the enforcement regime in deterring certain conduct. The penalty of 40 penalty units is also consistent with the Guide, which expresses a preference for a maximum of 60 penalty units for offences of strict liability.

 

Item [79] – Subparagraph 26A(4)(c)(iii)

 

This item repeals subparagraph 26A(4)(c)(iii) of the Principal Regulations and substitutes new subparagraphs 26A(4)(c)(iii) and (iv).

 

Subparagraph 26A(4)(c)(iii) previously required an operator to include in a written report of a reportable incident the corrective action that has been taken, or is proposed to be taken, to prevent a similar reportable incident. This requirement mixed the concepts of ‘corrective’ and ‘preventive’ actions, leading to potential confusion in relation to the information that is required to be provided. Often, corrective actions taken at the time of an incident are appropriate to stop the immediate cause of the incident, but may not prevent the occurrence of similar incidents in the future. 

 

This item clarifies the information required by specifying that the written report must include details of (a) the corrective action that has or is proposed to be taken to stop, control or remedy the reportable incident, and (b) the action that has or is proposed to be taken to prevent a similar incident occurring in the future.

 


 

Item [80] – At the end of regulation 26A

 

This item includes a new requirement for a titleholder to provide a copy of a written report of a reportable incident, which is required to be given to the Regulator under subregulation 26A(1), to the Titles Administrator and the Department of the responsible State or Northern Territory Minister within seven days of submitting the report to the Regulator.

 

Previously, under former regulation 26AA of the Principal Regulations, if an operator of an activity notified a reportable incident in accordance with regulation 26, the operator was required to provide a copy of the notification to the Titles Administrator and the Department of the responsible State Minister or the responsible Northern Territory Minister. However, there was not a similar requirement to provide a copy of a written report of a reportable incident to the Titles Administrator or Department of the responsible State Minister or the responsible Northern Territory Minister. The copy of the initial notification received by these authorities may be limited to a relatively brief statement that the incident has occurred, and therefore may not provide sufficient information in relation to the incident.

 

The written report required by regulation 26A of the Principal Regulations includes further details about incident causes, actions taken to avoid or mitigate environmental impacts, and further proposed actions to continue to remedy the incident and prevent similar incidents occurring in the future. This item provides for this report to be provided to the Titles Administrator and the Department of the responsible State Minister or the responsible Northern Territory Minister, and thereby ensure these authorities have sufficient information in relation to the reportable incident.

 

Under Division 2 of Part 9.6A of the OPGGS Act, if an obligation is imposed on a titleholder, and there are two or more registered holders of the same title, the obligation is imposed on each of the registered holders, but can be discharged by any one of them.

 

‘Responsible State Minister’ and ‘responsible Northern Territory Minister’ are defined in section 7 of the OPGGS Act. The responsible State Minister for all States other than Tasmania, and the responsible Northern Territory Minister, is the Minister who is the State or Northern Territory member of the Joint Authority for the relevant State or Northern Territory. The responsible State Minister for Tasmania is the Minister of Tasmania who is responsible for administering the Tasmanian Petroleum Submerged Lands Act.

 

As an example, therefore, if the incident occurred in the offshore area of Western Australia, the titleholder would be required to give a copy of the written report to the Department of the Western Australian Minister who is the State member of the Joint Authority for Western Australia.

 

Item [81] – Regulation 26AA

 

This item repeals regulation 26AA from the Principal Regulations. A requirement equivalent to that in regulation 26AA has instead been included in regulation 26 – see item 77.

 

This item also inserts a new regulation 26AA into the Principal Regulations, to enable the Regulator to require additional written reports of a reportable incident. Following notification of a reportable incident as required by regulation 26, and provision of a written report of the incident as required by regulation 26A, there was previously no requirement in the Regulations for further or on-going reporting in relation to the incident.

 

However, in the case of an on-going incident, further information may be necessary to ensure that the Regulator, the responsible Commonwealth Minister and the public remain informed about the status of the incident, incident response activities, and activities undertaken to prevent the occurrence of further incidents. In addition, the pre-existing requirement for a written report within three days of the occurrence of the incident may not provide the titleholder with a sufficient period to determine the root cause of the incident and to devise preventative actions to stop similar incidents occurring in the future.

 

New regulation 26AA enables the Regulator to request in writing that the titleholder provide further written reports of a reportable incident, including periodic reports, subsequent to the notification required by regulation 26 and written report required by regulation 26A. The written request by the Regulator should identify the information or matters to be addressed in the report, and specify a date or time for the report to be given to the Regulator. The specified date or time must give the titleholder a reasonable time to prepare the report.

 

Under Division 2 of Part 9.6A of the OPGGS Act, if an obligation is imposed on a titleholder, and there are two or more registered holders of the same title, the obligation is imposed on each of the registered holders, but can be discharged by any one of them.

 

Failure to submit a written report of a reportable incident in accordance with a notice given by the Regulator under regulation 26AA would be an offence of strict liability, punishable by 40 penalty units (subregulations 26AA(5) and (7)). Due to the operation of subsection 4B(3) of the Crimes Act 1914, the penalty that may be imposed on a body corporate for a breach of regulation 26AA is 200 penalty units.

 

The application of strict liability to an offence means that a fault element such as intention to do the act, or not do the act, is not required to be proved. This ensures that the regulation can be enforced more effectively as, given the remote and complex nature of offshore operations and the prevalence of multiple titleholder arrangements, it is extremely difficult to prove intent. The intention of the application of strict liability is therefore to improve compliance in the regulatory regime. This is consistent with the principles outlined in A Guide To Framing Commonwealth Offences, Infringement Notices and Enforcement Powers, September 2011, which include that the punishment of offences not involving fault may be appropriate where it is likely to significantly enhance the effectiveness of the enforcement regime in deterring certain conduct. The penalty of 40 penalty units is also consistent with the Guide, which expresses a preference for a maximum of 60 penalty units for offences of strict liability.

 

Under subregulation 26AA(6), it is a defence to a prosecution for an offence against subregulation 26AA(5) if the titleholder has a reasonable excuse. The defendant would bear an evidential burden in relation to the question whether he or she has a reasonable excuse. The burden of proof is reversed because the circumstances are likely to be exclusively within the knowledge of the defendant. This is particularly the case given the remote nature of offshore petroleum and greenhouse gas operations.

 


 

Item [82] – Subregulation 26B(1)

 

This item in effect removes the reference to an operator of an activity in subregulation 26B(1) of the Principal Regulations and replace it with a reference to a titleholder, so that a titleholder commits an offence if there is a recordable incident in relation to an activity and the titleholder does not submit a written report of the recordable incident in accordance with subregulation 26B(4). The concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance with the Regulations – see item 24.

 

Under Division 2 of Part 9.6A of the OPGGS Act, if an obligation is imposed on a titleholder, and there are two or more registered holders of the same title, the obligation is imposed on each of the registered holders, but can be discharged by any one of them.

 

The penalty for a failure to comply with subregulation 26B(1) remains at 40 penalty units, or 200 penalty units for an offence committed by a body corporate due to the operation of subsection 4B(3) of the Crimes Act 1914, and the offence continues to be an offence of strict liability. However, it would be the titleholder who is responsible for compliance. It is still appropriate to apply strict liability to the offence to ensure that the regulation can be enforced more effectively as, given the remote and complex nature of offshore operations and the prevalence of multiple titleholder arrangements, it is extremely difficult to prove intent. The intention of the application of strict liability is therefore to improve compliance in the regulatory regime. This is consistent with the principles outlined in A Guide To Framing Commonwealth Offences, Infringement Notices and Enforcement Powers, September 2011, which include that the punishment of offences not involving fault may be appropriate where it is likely to significantly enhance the effectiveness of the enforcement regime in deterring certain conduct. The penalty of 40 penalty units is also consistent with the Guide, which expresses a preference for a maximum of 60 penalty units for offences of strict liability.

 

Item [83] – Subparagraph 26B(4)(d)(iv)

 

This item repeals subparagraph 26B(4)(d)(iv) of the Principal Regulations and substitutes new subparagraphs 26B(4)(d)(iv) and (v).

 

Subparagraph 26B(4)(d)(iv) previously required an operator to include in a written report of a recordable incident the corrective action that has been taken, or is proposed to be taken, to prevent a similar recordable incident. This requirement mixed the concepts of ‘corrective’ and ‘preventive’ actions, leading to potential confusion in relation to the information that is required to be provided. Often, corrective actions taken at the time of an incident are appropriate to stop the immediate cause of the incident, but may not prevent the occurrence of similar incidents in the future. 

 

This item clarifies the information required by specifying that the written report must include details of (a) the corrective action that has or is proposed to be taken to stop, control or remedy the recordable incident, and (b) the action that has or is proposed to be taken to prevent a similar incident occurring in the future.

 


 

Item [84] – After regulation 26B

 

This item inserts a new regulation 26C into the Principal Regulations, to require titleholders to submit regular reports about their environmental performance to the Regulator.

 

Previously, subregulation 15(1) of the Regulations required an environment plan to include arrangements for recording, monitoring and reporting information about the activity, sufficient to enable the Regulator to determine whether the environmental performance objectives and standards in the environment plan are met. However, the Principal Regulations did not contain a clear, stand-alone requirement for titleholders to report their environmental performance against the environment plan, which could reinforce the requirement for regular submission of reports. In addition, NOPSEMA has advised that it was not receiving consistent environmental performance reports that contain a satisfactory level of information to enable NOPSEMA to assess whether or not the objectives and standards set out in the environment plan are being met.

 

The Regulation therefore repeals subregulation 15(1) (see item 53), and item 84 creates a new standalone requirement for regular reporting of environmental performance to the Regulator. A titleholder is required to state when the reports would be provided (no less than annually) in the implementation strategy of the environment plan (see new subregulation 14(2) (item 49)) and report information about its environmental performance to the Regulator at the intervals set out in the implementation strategy. Under Division 2 of Part 9.6A of the OPGGS Act, if an obligation is imposed on a titleholder, and there are two or more registered holders of the same title, the obligation is imposed on each of the registered holders, but can be discharged by any one of them.

 

The Regulator has the ability to request further information if the Regulator is not reasonably satisfied that the information in the report is sufficient to enable the Regulator to determine that the environmental performance outcomes and standards set out in the environment plan have been met. The Regulator is also required to identify the reasons it is not reasonably satisfied with the report, so that the titleholder can make modifications accordingly.

 

This amendment helps to create consistency in reporting requirements and ensure an adequate level of reporting is provided that is sufficient for the Regulator to assess whether the environment performance outcomes and standards set out in environment plans are being met. If after two or more requests for further information the Regulator is still not reasonably satisfied that the titleholder has provided sufficient information, the Regulator has the discretion to withdraw acceptance of the environment plan, in accordance with the procedures set out in Division 2.5 of the Principal Regulations – see new paragraph 23(2)(d) (item 66).

 

Item [85] – Regulation 27

 

This item repeals regulation 27 of the Principal Regulations, and replaces it with a new regulation 27.

 

In substance, the new regulation 27 largely reflects the requirements of regulation 27 of the current Regulations. However, the requirement to store specified records in a way that makes retrieval of the environment plan reasonably practicable is placed on the titleholder, rather than the operator. The concept of an ‘operator’ has been removed from the Regulations, and responsibility for compliance placed on the titleholder – see item 24. In addition, the new regulation has been restructured to clarify the requirements of the regulation.

 

Subregulation 27(1) makes it clear that the titleholder commits an offence if it does not store the environment plan in force for an activity, in a way that makes retrieval of the plan reasonably practicable, at all times while the plan is in force.

 

Subregulation 27(2) makes it clear that the titleholder commits an offence if it does not store a version of an environment plan that was previously in force in a way that makes retrieval of the version reasonably practicable. However, it would be a defence if it is more than five years after the day when the version ceased to be in force (subregulation 27(3)). For example, if the titleholder has an environment plan accepted on 7 April 2014, it would be required to store the plan under subregulation 27(1). If a proposed revision of the plan is subsequently submitted, and is accepted by the Regulator on 10 May 2015, the titleholder would be required to do both of the following:

·         Store the revised plan, which is now the environment plan in force, under subregulation 27(1); and

·         Store the version of the plan that had been accepted on 7 April 2014, and was in force until the revised plan was accepted, under subregulation 27(2) until 10 May 2020 (five years after the day it ceased to be in force because the revised plan was accepted by the Regulator).

 

For subregulations 27(2) and (3), a plan may no longer be in force either because the plan was revised, acceptance of the plan was withdrawn, or the operation of the plan ended.

 

Subregulation 27(4) makes it clear that the titleholder commits an offence if it creates a document or other record mentioned in subregulation 27(6), and does not store the document or record in a way that makes retrieval of the document or record reasonably practicable. However, it would be a defence if it is more than five years after the day that the document or record was created (subregulation 27(5)). 

 

The documents or other records mentioned in subregulation 27(6) are the same as the documents that are previously required to be kept under former paragraphs 27(2)(c) to (f) of the Principal Regulations, with the exception of the following:

·         Records relating to environmental performance, or the implementation strategy, under the environment plan, will be specifically required to be stored, in addition to written reports, to make clear that it is not only formal written reports that are required to be stored (paragraph 27(6)(b);

·         Records and copies of reports mentioned in new regulation 26AA (additional written reports about a reportable incident – see item 81) would be required to be stored, in addition to records and copies of reports mentioned in regulation 26 and 26A as previously required;

·         Records and copies of reports mentioned in new regulation 26C (relating to the titleholder’s environmental performance for an activity – see item 84) would be required to be stored.

 

Under Division 2 of Part 9.6A of the OPGGS Act, if an obligation is imposed on a titleholder, and there are two or more registered holders of the same title, the obligation is imposed on each of the registered holders, but can be discharged by any one of them.

 

The penalties for a failure to comply with subregulations 27(1), (2) or (4) remain at 30 penalty units, or 150 penalty units for an offence committed by a body corporate due to the operation of subsection 4B(3) of the Crimes Act 1914, and the offences would continue to be offences of strict liability. However, it would be the titleholder who is responsible for compliance. It is still appropriate to apply strict liability to the offence to ensure that the regulation can be enforced more effectively as, given the remote and complex nature of offshore operations and the prevalence of multiple titleholder arrangements, it is extremely difficult to prove intent. The intention of the application of strict liability is therefore to improve compliance in the regulatory regime. This is consistent with the principles outlined in A Guide To Framing Commonwealth Offences, Infringement Notices and Enforcement Powers, September 2011, which include that the punishment of offences not involving fault may be appropriate where it is likely to significantly enhance the effectiveness of the enforcement regime in deterring certain conduct. The penalty of 30 penalty units is also consistent with the Guide, which expresses a preference for a maximum of 60 penalty units for offences of strict liability.

 

As was previously the case, the defendant would bear an evidential burden in relation to the matters in subregulations 27(3) or (5). The burden of proof is reversed because the circumstances are likely to be exclusively within the knowledge of the defendant; for example, the defendant would know when it creates a particular document or record. This is particularly the case given the remote nature of offshore petroleum and greenhouse gas operations.

 

Item [86] – Subregulation 28(1)

 

This item repeals subregulation 28(1) of the Principal Regulations and substitutes a new subregulation 28(1) so that a titleholder, rather than an operator, commits an offence if the titleholder fails to make available copies of the records mentioned in regulation 27 (see item 85) in accordance with the requirements of regulation 28. The concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance with the Regulations – see item 24.

 

Under Division 2 of Part 9.6A of the OPGGS Act, if an obligation is imposed on a titleholder, and there are two or more registered holders of the same title, the obligation is imposed on each of the registered holders, but can be discharged by any one of them.

 

The penalty for a failure to comply with subregulation 28(1) remains at 30 penalty units, or 150 penalty units for an offence committed by a body corporate due to the operation of subsection 4B(3) of the Crimes Act 1914, and the offence would continue to be an offence of strict liability. However, it would be the titleholder who is responsible for compliance. It is still appropriate to apply strict liability to the offence to ensure that the regulation can be enforced more effectively as, given the remote and complex nature of offshore operations and the prevalence of multiple titleholder arrangements, it is extremely difficult to prove intent. The intention of the application of strict liability is therefore to improve compliance in the regulatory regime. This is consistent with the principles outlined in A Guide To Framing Commonwealth Offences, Infringement Notices and Enforcement Powers, September 2011, which include that the punishment of offences not involving fault may be appropriate where it is likely to significantly enhance the effectiveness of the enforcement regime in deterring certain conduct. The penalty of 30 penalty units is also consistent with the Guide, which expresses a preference for a maximum of 60 penalty units for offences of strict liability.

 

Item [87] – Paragraph 28(2)(b)

 

This item repeals paragraph 28(2)(b) of the Principal Regulations, which contained an incorrect reference to a delegate of the Regulator under section 52 of the OPGGS Act. Under regulation 4 of the Principal Regulations, NOPSEMA is the Regulator in relation to petroleum activities. However NOPSEMA, as an entity, cannot delegate powers or functions.

 

The responsible Commonwealth Minister is the Regulator in relation to greenhouse gas activities, and is able to delegate powers and functions under section 778 of the OPGGS Act. This item therefore also substitutes a new paragraph 28(2)(b) to refer to a delegate, under section 778 of the Act, of the responsible Commonwealth Minister.

 

Item [88] – Paragraph 28(5)(a)

 

This item omits the words ‘the activity’ in paragraph 28(5)(a) of the Principal Regulations and substitute ‘an activity’. This is a grammatical change as a consequence of the removal of the reference to an ‘operator for an activity’ in subregulation 28(1) – see item 86.

 

Item [89] – Paragraph 28(5)(b)

 

This item omits the words “on any day, other than a Saturday, a Sunday or a public holiday at” from paragraph 28(5)(b) of the Principal Regulations and substitute “on a business day in”. This reflects section 2B of the Acts Interpretation Act 1901 which defines a ‘business day’ as “a day that is not a Saturday, a Sunday or a public holiday in the place concerned”.

 

Item [90] – Subregulation 28(6)

 

This item omits the reference to ‘nominated address’ from subregulation 28(6) and substitute ‘place where the records are kept’. This change is a consequence of the removal of the concept of an ‘operator’ from the Principal Regulations – see item 24. Previously, under paragraph 32(3)(a) of the Regulations, the operator was required to give an address for communications on matters relating to the activity. This was defined as the ‘nominated address’ in subregulation 4(1). However, the definition of ‘nominated address’ and paragraph 32(3)(a) have been repealed by the Regulation (see items 22 and 91 respectively).

 

This item amends subregulation 28(6) to instead require a titleholder to make copies of records available at the place where the records are kept, or at any other place agreed between the titleholder and the person requesting to have access to the records under regulation 28.

 


 

Item [91] – Divisions 4.1 and 4.2

 

This item repeals Divisions 4.1 and 4.2 of the Principal Regulations, and replaces them with new Divisions 4.1 (information requirements) and 4.2 (fees).

 

Division 4.1 of the Principal Regulations previously related specifically to the measurement and management of petroleum discharged in produced formation water (PFW). The regulations in this Division were quite prescriptive within the context of objective-based regulations, and did not reinforce the principles of managing risks and impacts to as low as reasonably practicable and an acceptable level, or continuous improvement.

 

This Division appeared to be a carryover from the former Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production 1995, and stemmed from an engineering specification used in the Gulf of Mexico in the 1970s. This was considered to be the limit at which a visible sheen could not be observed and was as low as the available technology of the day could achieve.

 

To ensure consistency with the objects of the Regulations, the prescriptive requirements in Division 4.1 have been repealed by this item. Discharges of PFW are instead monitored and managed in the same way as other emissions and discharges from offshore petroleum facilities are required to be monitored and managed, in accordance with the implementation strategy required under regulation 14 (see item 52), to ensure that the impacts and risks of such discharges are reduced to as low as reasonably practicable and an acceptable level.   

 

Division 4.2 of the Principal Regulations previously provided for matters relating to operators of activities. As the concept of an ‘operator’ has been removed from the Regulations (see item 24), this item repeals Division 4.2.

 

A new Division 4.1 (regulations 29 to 31) has been inserted by this item.

 

Regulation 29 – Notifying start and end of activity

Paragraph 13(1)(c) of the Principal Regulations requires, among other things, an environment plan to contain information about an activity, including proposed timetables. However, the Regulations did not previously require notification to the Regulator of the actual start or end dates of activities. As a result, the Regulator may not have been aware that an activity is occurring, or that it has ceased, in particular if the actual timing of the activity differs from that originally proposed in the environment plan (such as, for example, if poor weather delayed the commencement of an activity). This could have ramifications for compliance inspections, planning, and tracking of performance reports, as well as resulting in the Regulator not receiving important information about the timing of activities in Commonwealth waters.

 

New regulation 29 therefore requires titleholders to notify the Regulator that an activity is to commence, at least ten days before the activity commences. It also requires titleholders to notify the Regulator that an activity is completed within ten days after the completion of the activity.

 

If an environment plan relates to more than one activity, the titleholder needs to notify the commencement and completion of each of those activities.

 

Under Division 2 of Part 9.6A of the OPGGS Act, if an obligation is imposed on a titleholder, and there are two or more registered holders of the same title, the obligation is imposed on each of the registered holders, but can be discharged by any one of them.

 

Regulation 30 – Notifying certain operations to State or Territory

Sub-regulation 15(2) of the Principal Regulations previously required that an environment plan must include arrangements for the operator to notify the Department of the responsible State Minister or the responsible Northern Territory Minister before the proposed date of commencement of drilling operations or seismic survey operations that are being carried out under the authority of the title if:

a)      There is a community in the area where the drilling operations or seismic survey operations will be carried out; and

b)      The drilling operations or seismic survey operations may have an effect on the community.

 

In its previous form, this requirement was unclear and had the potential to lead to inconsistent notification. For example, given that the activities regulated under the Principal Regulations will take place at least three nautical miles from the territorial sea baseline, it is difficult to envisage that there will be a ‘community in the area’ where the activities will take place. In addition, State and Northern Territory governments have advised that notification of commencement of all drilling and seismic activity is required to facilitate State/Northern Territory economic and social planning, and on public interest grounds.

 

In addition, the Regulations required arrangements for notification of the relevant Department of the commencement of operations to be set out in the environment plan. There was not a clear, standalone requirement for titleholders to notify the relevant Department of the commencement of the operations to reinforce the notification requirements.

 

Regulation 30 therefore provides a new standalone requirement for titleholders to notify the proposed date of commencement of any drilling operations or seismic survey operations to the Department of the responsible State Minister or responsible Northern Territory Minister, before the commencement of those operations. Subregulation 15(2) has been repealed – see item 53.

 

‘Responsible State Minister’ and ‘responsible Northern Territory Minister’ are defined in section 7 of the OPGGS Act. The responsible State Minister for all States other than Tasmania, and the responsible Northern Territory Minister, is the Minister who is the State or Northern Territory member of the Joint Authority for the relevant State or Northern Territory. The responsible State Minister for Tasmania is the Minister of Tasmania who is responsible for administering the Tasmanian Petroleum Submerged Lands Act.

 

As an example, therefore, if the operations are to take place in the offshore area of Western Australia, the titleholder would be required to notify the Department of the Western Australian Minister who is the State member of the Joint Authority for Western Australia.

 

The provision does not specify when the titleholder has to notify the relevant Department of the proposed date of commencement, other than to require that it be before the commencement of operations. Although there is in effect be no restriction on when the titleholder must notify the relevant Department, it is expected that the titleholder would do so closer to the proposed date, to allow for the possibility that changes may be made to the actual date of commencement. In addition, although it is not expected nor required that the titleholder would notify the Department again if the actual date of commencement would be different from, but proximal to, the proposed date, there is an expectation (although not a requirement) that they would do so if the actual date of commencement ended up being significantly different from the proposed date originally notified to the Department.

 

Failure to notify the Department of the responsible State Minister or responsible Northern Territory Minister in accordance with regulation 30 is an offence of strict liability, punishable by 30 penalty units. Due to the operation of subsection 4B(3) of the Crimes Act 1914, the penalty that may be imposed on a body corporate for a breach of regulation 30 is 150 penalty units.

 

The application of strict liability to an offence would mean that a fault element such as intention to do the act, or not do the act, is not required to be proved. This would ensure that the regulation can be enforced more effectively as, given the remote and complex nature of offshore operations and the prevalence of multiple titleholder arrangements, it is extremely difficult to prove intent. The intention of the application of strict liability is therefore to improve compliance in the regulatory regime. This is consistent with the principles outlined in A Guide To Framing Commonwealth Offences, Infringement Notices and Enforcement Powers, September 2011, which include that the punishment of offences not involving fault may be appropriate where it is likely to significantly enhance the effectiveness of the enforcement regime in deterring certain conduct. The penalty of 30 penalty units is also consistent with the Guide, which expresses a preference for a maximum of 60 penalty units for offences of strict liability.

 

Under Division 2 of Part 9.6A of the OPGGS Act, if an obligation is imposed on a titleholder, and there are two or more registered holders of the same title, the obligation is imposed on each of the registered holders, but can be discharged by any one of them.

 

Regulation 31 – Titleholder may refer to information previously given

In addition to environmental management, NOPSEMA is the regulator of occupational health and safety (OHS) for offshore petroleum and greenhouse gas storage operations, and also for structural integrity of facilities, wells and well-related equipment. NOPSEMA therefore receives information from titleholders (or facility operators in the case of OHS) for the purposes of assessments and approvals under the OPGGS Act or other regulations under the OPGGS Act that relate to those regulatory functions. In some cases, that information may also be relevant for the purposes of assessing compliance with the requirements of the Principal Regulations. For example, technical information on the structure and layout of a facility, which is provided in some detail in a safety case, may also be relevant for the assessment of an environment plan. A titleholder is required to provide general details of the construction and layout of a facility in an environment plan, and it may be useful for a titleholder to reference the safety case if NOPSEMA requires any further detail on this aspect.

 

In order to remove duplication of process and increase efficiencies for industry, regulation 31 specifically enables titleholders to reference information or documentation that has previously been provided to the Regulator, rather than provide the same information or documentation again, for the purpose of the Principal Regulations.

 

To ensure flexibility within the provision, it would not be necessary that the information or documentation that was previously submitted to the Regulator have been submitted by the titleholder. For example, assume Company X is the proponent who submits an offshore project proposal. The proposal may include a large amount of detail describing the environment in which a particular activity is to take place. If that detail is also applicable for the content of the subsequent environment plan for that activity, the plan could refer to the detail already provided in the offshore project proposal, rather than including all of the detail again. However, the titleholder who is required to include the information in the environment plan may not be Company X who previously provided the information (e.g. the titleholder may be a group of companies, or possibly may not even include Company X). By not specifying who must have previously submitted the information, the titleholder would be able to refer to the previously provided information, even though it was not the titleholder who submitted it.

 

In the event that, for any reason, information provided previously is no longer available to the Regulator, subregulation 31(2) enables the Regulator to inform the titleholder that the information is no longer available and the titleholder would be required to re-submit the information or documentation.

 

Subregulation 31(3) makes clear that information accepted by the Regulator in the context for which it was initially submitted will not automatically be taken to be acceptable for the purpose of the relevant provision/s of the Principal Regulations. The purpose of the new regulation is to avoid duplicative effort for the titleholder, and does not provide a guarantee that previously accepted information will be acceptable for all purposes.

 

A new Division 4.2 (regulation 32) has also been inserted by this item.

 

Regulation 32 – Offshore project proposals

Regulation 32 requires payment of a fee to NOPSEMA, on behalf of the Commonwealth, for the expenses incurred by NOPSEMA in considering an offshore project proposal (see Part 1A – item 35).

 

NOPSEMA’s functions under the OPGGS Act and regulations are fully cost-recovered through levies and fees payable by the offshore petroleum and greenhouse gas storage industries. Previously, there was no levy or fee payable that would recover NOPSEMA’s costs of administering the new regulations regarding offshore project proposals. Under subsection 685(1) of the OPGGS Act, the regulations may provide for the payment to NOPSEMA, on behalf of the Commonwealth, of fees in respect of matters in relation to which expenses are incurred by NOPSEMA under the OPGGS Act or regulations.

 

The fee would be due when NOPSEMA issues an invoice for the fee to the person who submitted the proposal, and payable in accordance with the invoice. The total amount of the fee would not exceed the total of the expenses incurred by NOPSEMA in considering the proposal. Therefore, if a proposal is withdrawn before a decision is made to accept or refuse to accept the proposal, the fee would represent NOPSEMA’s expenses in considering the proposal to whatever point is reached.

 

A fee will be required to be paid by all persons who submit an offshore project proposal, whether the proposal is submitted under subregulation 5A(1) or subregulation 5F(2) (see new subregulation 5F(3)).

 

Item [92] – Part 5 (heading)

 

This item amends the heading to Part 5 of the Principal Regulations as this Part would, as a result of amendments in the Regulation, include transitional arrangements relating to amendments under more than one set of amending regulations.

 

Item [93] – Before regulation 38

 

This item places the provisions that currently make up Part 5 of the Principal Regulations into a new Division 5.1 of Part 5. A new Division 5.2 has been added to provide for transitional arrangements relating to the Regulation – see item 98.

 

Item [94] – Regulation 38 (heading)

 

This item replaces the heading to regulation 38 of the Principal Regulations, as a consequence of the amendment at item 93.

 

Item [95] – Regulation 38

 

This item replaces the first reference to ‘Part’ in regulation 38 of the Principal Regulations with a reference to ‘Division’, as a consequence of the amendment under item 93.

 

Item [96] – Regulation 39

 

This item repeals regulation 39 of the Principal Regulations. This is a legacy item from the transition to the single national regulator that is no longer required.

 

Item [97] – Subregulation 40(1)

 

This item amends subregulation 40(1) to reflect that the definition of ‘accepted’, in relation to an environment plan, has been repealed by item 4 and a definition of ‘in force’, in relation to an environment plan, inserted by item 20. There is no change to the effect of subregulation 40(1).

 

Item [98] – At the end of Part 5

 

This item inserts a new Division 5.2 (regulations 42 to 48) to provide for transitional arrangements relating to the Regulation.

 

Regulation 42 – Definitions for Division 5.2

Regulation 42 defines ‘amending Regulation’ and ‘old Regulations’, for the purposes of the transitional provisions that have been inserted by this item.

 

Regulation 43 – Environment plan accepted before commencement of amendments

Regulation 43 ensures that, if an environment plan was in force immediately before 28 February 2014 (when Schedule 1 to the Regulation commences), it will continue to be in force after commencement of the Regulation. As a result of other amendments that have been made by the Regulation, the titleholder under whose title the activity or activities to which the plan relates are undertaken becomes become responsible for compliance with the environment plan that is continued in force.

 

If the titleholder proposes to change the manner in which the environmental impacts and risks of the activity are managed from the way they are managed under the environment plan that is continued in force, it must submit a proposed revision of the environment plan by 31 August 2014 – see item 54 (new subregulations 17(8) and (9)).

 

Regulation 44 – Environment plan submitted but not accepted before commencement of amendments

Regulation 44 applies if the operator of an activity submits an environment plan or proposed revision of an environment plan, and the Regulator has not yet made a decision to accept or refuse to accept the plan or proposed revision, before Schedule 1 to the Regulation commences.

 

From commencement of the Regulation, the environment plan or proposed revision is taken to have been submitted by the titleholder on the date that it was submitted by the operator. This ensures the Regulator can continue to assess the submitted plan or proposed revision, and avoids potential delays if a titleholder were required to submit the plan or proposed revision again.

 

The reference in subregulation 44(2) to ‘the titleholder for the activity’ is simply a reference to the titleholder.

 

In the case of an environment plan submitted by the operator under regulation 9 of the Principal Regulations, the titleholder could withdraw the plan before the Regulator makes a decision to accept or refuse to accept the plan under new subregulation 9(9) (see item 42), if it decides it does not want the Regulator to make a decision on the basis of that submitted plan. 

 

If the plan or proposed revision is accepted by the Regulator, and the titleholder proposes to change the manner in which the environmental impacts and risks of the activity are managed from the way they are managed under the plan, it must submit a proposed revision of the plan within six months after the day on which the Regulator notifies the titleholder that the plan or proposed revision was accepted – see item 54 (new subregulations 17(10) and (11)).

 

Subregulation 44(3) requires the Regulator to make a decision on an environment plan or proposed revision submitted by the operator prior to the commencement of Schedule 1 to the Regulation on 28 February 2014, having regard to the requirements of the Principal Regulations as in force prior to 28 February 2014, as the plan or proposed revision would have been developed and submitted on the basis of those requirements.

 

Regulation 45 – Notice given under old Regulations of intention to withdraw acceptance of environment plan

Regulation 45 provides that any notice of intention to withdraw the acceptance of an environment plan given to an operator before the commencement of the Regulation, and in relation to which a final decision to withdraw the acceptance has not been made, is no longer of effect. After commencement of the Regulation, the Principal Regulations clearly and appropriately ensure that the titleholder is responsible for non-compliance with environmental obligations under the Act and regulations. However, given that this is not the case under the Regulations as previously in force, it is not considered appropriate to hold the titleholder responsible for non-compliance of an operator prior to commencement of the Regulation.    

 

In addition, the Regulator cannot be able to give a notice of intention to withdraw the acceptance of an environment plan to the titleholder after the commencement of the Regulation on the basis of any non-compliance by an operator pre-commencement.

 

Regulation 46 – Reporting and recording requirements for operators

Regulation 46 provides transitional arrangements in relation to continued responsibility of the operator for incident notification and reporting, and requirements to store and make records available.

 

If a reportable incident occurs before Schedule 1 to the Regulation commences on 28 February 2014, the operator would be responsible for notification and reporting requirements under regulations 26, 26A and 26AA of the Principal Regulations as in force prior to 28 February 2014, even if those obligations would continue after 28 February 2014.

 

For example, if a reportable incident occurs, or the operator first becomes aware that a reportable incident occurred, at 11:30pm on 27 February 2014, the operator would be required to notify the Regulator of the incident within two hours (i.e. by 1:30am on 28 February 2014), in accordance with regulation 26 of the Principal Regulations as currently in force, even though the Regulation commences at midnight. The requirement in regulation 26AA of the Principal Regulations as currently in force would also continue to apply to the operator, and the operator would also be required to submit a written report of the reportable incident to the Regulator within three days (i.e. by 2 March 2014), or another period agreed with the Regulator, under regulation 26A of the Principal Regulations as in force before commencement of the Regulation.

 

The titleholder will not have notification or reporting responsibilities in relation to an incident that occurs prior to 28 February 2014. In addition, the Regulator will not be able to require the operator to provide additional written reports about any such incident under new regulation 26AA (see item 81).

 

If a recordable incident occurs at any time between 1 February 2014 and 27 February 2014 inclusive, prior to the commencement of Schedule 1 to the Regulation on 28 February 2014, the operator will continue to be required to submit a written report of the recordable incident as soon as practicable after the end of February, but no later than 15 March 2014, in accordance with regulation 26B of the Principal Regulations as in force prior to the commencement of the Regulation.

 

If a recordable incident occurs on 28 February 2014, the titleholder will be responsible for submitting a written report of the recordable incident as soon as practicable after the end of February, but no later than 15 March 2014, in accordance with regulation 26B as amended by the Regulation.

 

The requirements of regulations 27 and 28 of the Principal Regulations, as in force prior to the commencement of the Regulation on 28 February 2014, will also continue to apply to an operator after commencement of the Regulation. Operators will therefore be required to continue to store the documents or records mentioned in subregulation 27(2) of the Principal Regulations for five years from the making of the document or record, in a way that makes retrieval of the document or record reasonably practicable. For example, if an operator made a record of a report relating to recordable incidents on 10 December 2012, the operator must store the document until 10 December 2017, despite the amendments that are made by the Regulation. The continued requirement will only apply in relation to documents or records made prior to the commencement of the Regulation.   

 

In addition, the operator will continue after commencement of the Regulation to be subject to the requirement under regulation 28 of the Principal Regulations to make copies of the records mentioned in regulation 27 that were made before commencement of the Regulation available on request by the Regulator, a delegate of the Regulator, a greenhouse gas project inspector, a petroleum project inspector or a Greater Sunrise visiting inspector, or an agent of one of those persons.

 

Regulation 47 – Reporting on environmental performance

New regulation 26C (see item 84) inserts a new standalone requirement for a titleholder to submit regular reports to the Regulator in relation to the titleholder’s environmental performance for an activity. This replaces subregulation 15(1) of the Principal Regulations, which currently requires an environment plan to include arrangements for recording, monitoring and reporting information about the activity, not less than annually, sufficient to enable the Regulator to determine whether the environmental performance objectives and standards in the environment plan are met.

 

Environment plans continued in force by regulation 43, or submitted prior to commencement of the Regulation but accepted after commencement in accordance with regulation 44, would include arrangements for reporting in the environment plan in accordance with the requirements of subregulation 15(1) of the Principal Regulations as currently in force. Therefore, regulation 47 ensures that new regulation 26C would not apply to a titleholder if:

·         The titleholder has inherited an environment plan that was in force before 28 February 2014 and the plan has not subsequently been revised;

·         The titleholder has inherited an environment plan that was in force before 28 February 2014 and any revision of the plan was submitted to the Regulator by the operator before 28 February 2014; or

·         The plan was submitted to the Regulator by the operator under regulation 9 before 28 February 2014, and is subsequently accepted by the Regulator.

 

The titleholder will be required to report in accordance with the arrangements in the environment plan, until either the plan is revised, or the operation of the plan ends.

 

Regulation 48 – Notifying operations

New regulation 30 (see item 91) inserts a standalone requirement for a titleholder to notify the Department of the responsible State Minister or responsible Northern Territory Minister of the proposed date of commencement of drilling operations or seismic survey operations, prior to the commencement of those operations. This replaces subregulation 15(2), which currently requires an environment plan to include arrangements for the operator to notify the Department of the responsible State or Northern Territory Minister before the proposed date of commencement of drilling operations or seismic survey operations in certain circumstances.

 

Environment plans continued in force by regulation 43, or submitted prior to commencement of the Regulation but accepted after commencement in accordance with regulation 44, would include arrangements for notifying the responsible State or Northern Territory Minister in the environment plan in accordance with the requirements of subregulation 15(2) of the Principal Regulations as previously in force. Therefore, regulation 48 ensures that new regulation 30 will only apply to a titleholder if the environment plan for the relevant seismic or drilling operation was submitted to the Regulator under regulation 9 on or after the commencement of the Regulation on 28 February 2014.

 

Titleholders that have inherited an environment plan that is continued in force, or a plan that is submitted prior to commencement of the Regulation but accepted after commencement in accordance with regulation 44, will be required to notify the responsible State or Northern Territory Minister in accordance with the arrangements in the environment plan.

 

Item [99] – Amendments of listed provisions

 

This item amends the listed provisions of the Principal Regulations to remove references to an ‘operator’ and replace them with references to a ‘titleholder’. The concept of an ‘operator’ has been removed from the Principal Regulations and the titleholder made responsible for compliance – see item 24.

 

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

 

Item [100] – Subregulations 59E(1) and (2)

 

This item replaces references to subregulation 11(3) with references to regulation 10 in subregulations 59E(1) and (2) of the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Regulations 2004 (Regulatory Levies Regulations), as a consequence of amendments to the Principal Regulations made by the Regulation. As a result of the amendments in item 42, the Regulator will accept or refuse to accept an environment plan or proposed revision of an environment plan under regulation 10, rather than subregulation 11(3).

 

Item [101] – At the end of regulation 59E

 

This item inserts a new subregulation 59E(3) in the Regulatory Levies Regulations, as a consequence of an amendment made by item 42 of the Regulation. Item 42 insertsa new subregulation 9(9) which will specifically enable a titleholder to withdraw an environment plan submitted to the Regulator at any time before the Regulator has made a decision to accept or refuse to accept the plan.

 

Under section 10F of the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Act 2003 (Regulatory Levies Act), environment plan levy is imposed on a titleholder on the submission of an environment plan to NOPSEMA under regulation 9 of the Principal Regulations. Environment plan levy includes two components; an activity amount which is effectively designed to recover the costs of work done by NOPSEMA in assessing an environment plan, and a compliance amount which is to cover the cost of ongoing compliance activities in relation to the activity or activities to which the plan relates.

 

If the titleholder withdraws a submitted environment plan in accordance with subregulation 9(9), before the Regulator makes a decision to accept or refuse to accept the plan, the titleholder should not be required to pay the compliance amount, as the activity or activities to which the plan relates cannot be undertaken without an accepted environment plan. Therefore, no compliance activities will take place in relation to the activity or activities to which the plan relates.

 

Environment plan levy is payable on submission of the environment plan. The compliance amount of environment plan levy is due in equal annual instalments during the period of the environment plan. The first instalment is due 30 days after the submission of the plan, and each subsequent instalment is due at the beginning of each calendar year after the submission of the environment plan. 

 

This item therefore inserts a new subregulation in the Regulatory Levies Regulations that requires the Regulator to refund each instalment of the compliance amount that has already been paid (if any), and remit each instalment of the compliance amount that has not yet been paid. In effect, the titleholder is therefore only required to pay the activity amount. 

 

Item [102] – Subregulations 59I(1) and (2)

 

This item replaces references to subregulation 11(3) with references to regulation 10 in subregulations 59I(1) and (2) of the Regulatory Levies Regulations, as a consequence of amendments to the Principal Regulations made by the Regulation. See discussion under item 100.

 

Item [103] – At the end of regulation 59I

 

This item inserts a new subregulation 59I(3) in the Regulatory Levies Regulations, as a consequence of an amendment made by item 42 of the Regulation. Item 42 inserts a new subregulation 9(9) which will specifically enable a titleholder to withdraw an environment plan submitted to the Regulator at any time before the Regulator has made a decision to accept or refuse to accept the plan.

 

Section 10G of the Regulatory Levies Act applies if a State or Territory has conferred regulatory functions in relation to offshore petroleum and/or offshore greenhouse gas environmental management on NOPSEMA in connection with operations in the designated coastal waters of that State or Territory under the relevant State or Territory legislation. Under section 10G, environment plan levy is imposed on the holder of a State/Territory title on the submission of an environment plan to NOPSEMA under a regulation of the State or Territory that substantially corresponds to regulation 9 of the Principal Regulations. Environment plan levy includes two components; an activity amount which is effectively designed to recover the costs of work done by NOPSEMA in assessing an environment plan, and a compliance amount which is to cover the cost of ongoing compliance activities in relation to the activity or activities to which the plan relates.

 

If the holder of a State/Territory titles withdraws a submitted environment plan under the provision in a law of the State or Territory that substantially corresponds to subregulation 9(9) of the Principal Regulations, before the Regulator makes a decision to accept or refuse to accept the plan, the titleholder should not be required to pay the compliance amount, as the activity or activities to which the plan relates cannot be undertaken without an accepted environment plan. Therefore, no compliance activities will take place in relation to the activity or activities to which the plan relates.

 

Environment plan levy is payable on submission of the environment plan. The compliance amount of environment plan levy is due in equal annual instalments during the period of the environment plan. The first instalment is due 30 days after the submission of the plan, and each subsequent instalment is due at the beginning of each calendar year after the submission of the environment plan. 

 

This item therefore inserts a new subregulation in the Regulatory Levies Regulations that would require the Regulator to refund each instalment of the compliance amount that has already been paid (if any), and remit each instalment of the compliance amount that has not yet been paid. In effect, the titleholder is therefore only be required to pay the activity amount.

 

Schedule 2 – Amendments commencing the same time as Schedule 1 to the Offshore Petroleum and Greenhouse Gas Storage Amendment (Compliance Measures) Act 2013 commences

 

Offshore Petroleum and Greenhouse Gas Storage (Environment) Regulations 2009

 

Item [1] – Paragraphs 28(2)(c) and (4)(b)

 

Paragraphs 28(2)(c) and (4)(b) of the Principal Regulations included references to a ‘petroleum project inspector’. Amendments to the OPGGS Act that will be made on commencement of Schedule 1 to the Offshore Petroleum and Greenhouse Gas Storage Amendment (Compliance Measures) Act 2013 (Compliance Measures Amendment Act) will remove petroleum project inspectors from the regime established by the OPGGS Act. Instead, NOPSEMA will have the ability to appoint ‘NOPSEMA inspectors’ to monitor and investigate compliance by persons with their petroleum-related obligations under the OPGGS Act and regulations. This item therefore amends paragraphs 28(2)(c) and (4)(b) when Schedule 1 to the Compliance Measures Amendment Act commences to remove the references to a ‘petroleum project inspector’, and replaces them with references to a ‘NOPSEMA inspector’.

 

Schedule 1 to the Compliance Measures Amendment Act is scheduled to commence immediately after the commencement of Parts 2 and 3 of the proposed Regulatory Powers (Standard Provisions) Act.


STATEMENT OF COMPATIBILITY WITH HUMAN RIGHTS

Prepared in accordance with Part 3 of the Human Rights (Parliamentary Scrutiny) Act 2011

Offshore Petroleum and Greenhouse Gas Storage Legislation Amendment (Environment Measures) Regulation 2014

This Regulation is compatible with the human rights and freedoms recognised or declared in the international instruments listed in section 3 of the Human Rights (Parliamentary Scrutiny) Act 2011.

Overview of the Regulation

The Regulation makes various amendments to the Offshore Petroleum and Greenhouse Gas Storage (Environment) Regulations 2009 (the Environment Regulations) and the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Regulations 2004 to facilitate streamlining of environmental approvals for offshore petroleum and greenhouse gas activities under the OPGGS Act and the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act), and implement the findings of a review of the Environment Regulations.

The principal amendments made by the Regulation include:

·         Strengthening the object of the Environment Regulations to include specific reference to the core concepts of ensuring environmental impacts and risks will be reduced to as low as reasonably practicable and of an acceptable level;

·         Clarification of the definition of ‘petroleum activity’;

·         Transfer of responsibility for compliance with the Environment Regulations from the operator of an activity to the titleholder;

·         Clarification of the process for assessment of an environment plan;

·         Clarification of the requirement for an environment plan to provide for monitoring arrangements for both normal operations and emergency conditions;

·         Clarification of incident reporting requirements, including provision for the Regulator to request additional written reports of reportable incidents;

·         Insertion of a new regulation which would provide a standalone requirement for titleholders to submit reports to the Regulator about their environment performance no less than annually;

·         Introduction of a requirement for the Regulator to publish a notification of a proposed activity on its website on submission of an environment plan by a titleholder;

·         Introduction of a new environmental assessment process, the ‘offshore project proposal’, to capture large-scale petroleum developments that are likely to have a significant impact on matters protected under Part 3 of the EPBC Act, and provide for a mandatory public consultation process for those developments; and

·         Introduction of an acceptance criterion for environment plans whereby the Regulator cannot accept an environment plan for an activity or part of an activity being undertaken in any part of a declared World Heritage property.

 


 

Human rights implications

The Regulation engages the following human rights:

·         The presumption of innocence;

·         The protection against arbitrary interference with privacy.

The presumption of innocence

The amendments in Schedule 1 to this Regulation engage the right to be presumed innocent until proved guilty according to law in article 14(2) of the International Convention on Civil and Political Rights due to:

·         Introduction of two new offences of strict liability;

·         Transfer of responsibility for compliance with certain provisions, for which the failure to comply is an offence of strict liability;

·         Introduction of an offence provision, which includes a defence that places an evidential burden on the defendant.

Article 14(2) imposes on the prosecution the burden of proving the charge and guarantees that no guilt can be presumed until the charge has been proved beyond reasonable doubt. This right may be subject to permissible limitations where those limitations are provided by law and non-arbitrary. In order for limitations not to be arbitrary, they must be aimed at a legitimate objective and be reasonable, necessary and proportionate to that objective.

Strict liability

The Regulation introduces new offences of strict liability in regulation 26AA (requirement to submit additional written reports of reportable incidents if requested by the Regulator) and regulation 30 (requirement to notify the Department of the responsible State Minister or the responsible Northern Territory Minister of the proposed date of commencement of seismic survey or drilling operations).

It also continues existing offences of strict liability; however responsibility for compliance with the relevant provisions has transferred from the operator of an activity to the titleholder.

 

1)        Legitimate objective

Strict liability has been applied to these offence provisions to enhance the effectiveness of the provisions in deterring certain conduct, and thereby reduce the likelihood of non-compliance which could have potentially severe environmental consequences.

 

2)        Reasonable, necessary and proportionate response

Given the nature of offshore petroleum and greenhouse gas operations, there is a risk of severe environmental consequences if titleholders fail to comply with their regulatory obligations. In addition, the remote and complex nature of offshore operations and the prevalence of multiple titleholder arrangements mean it is extremely difficult to prove intent. Application of strict liability to the relevant offence provisions is therefore necessary to ensure that the relevant regulations can be enforced more effectively, and thereby improve compliance with the regulatory regime. This is consistent with the principles outlined in A Guide To Framing Commonwealth Offences, Infringement Notices and Enforcement Powers, September 2011 (the Guide), which include that the punishment of offences not involving fault may be appropriate where it is likely to significantly enhance the effectiveness of the enforcement regime in deterring certain conduct.

The penalties imposed for failure to comply with the two new strict liability offences and most of the continued strict liability offences are consistent with the Guide, which expresses a preference for a maximum of 60 penalty units for offences of strict liability.

Three of the continued strict liability offences continue to apply a penalty of 80 penalty units. It is appropriate to continue to apply this penalty, noting this is higher than the preference stated in the Guide for a maximum of 60 penalty units. The penalty of 80 penalty units applies to the three most serious offences within the Environment Regulations; namely, undertaking an activity without an environment plan in force for the activity, undertaking an activity in a manner that is contrary to the environment plan in force, and continuing to undertake an activity after the occurrence of any significant new or significant increase in an existing environmental impact or risk not provided for in the environment plan in force. The potential for serious environmental consequences resulting from a breach of these provisions justifies the application of a higher penalty. In addition, offshore resources activities, as a matter of course, require a very high level of expenditure. Therefore by comparison a smaller penalty would be an ineffective deterrent. 

In terms of the right to the presumption of innocence as afforded to individuals, the reality is that in the offshore regulatory regime investigations and prosecutions are conducted largely, if not solely, in relation to companies, not individuals. Prosecutions to date have only been in relation to companies, and it is not anticipated that this regulatory approach would change in the future given the nature of the industry and the requirements imposed.

Placement of evidential burden on a defendant

The Regulation introduces a new regulation 26AA, which requires a titleholder to submit additional written reports of reportable incidents if requested to do so by the Regulator. Subregulation 26AA(5) makes it an offence to fail to comply with such a request from the Regulator. Under subregulation 26AA(6), it would be a defence to a prosecution for an offence against subregulation 26AA(5) if the titleholder has a reasonable excuse. The titleholder would bear an evidential burden in relation to the question whether it has a reasonable excuse.

 

1)      Legitimate objective

Placing an evidential burden on the defendant in this case would ensure that a titleholder that asserts it has a reasonable excuse for failing to comply with regulation 26AA bears the evidential burden of proving that matter.

 

2)      Reasonable, necessary and proportionate response

The circumstances of the defence (i.e. whether the titleholder has a reasonable excuse) are likely to be exclusively within the knowledge of the titleholder. This is particularly the case given the remote nature of offshore petroleum and greenhouse gas operations. It is therefore reasonable to require the defendant to adduce evidence in relation to this defence.

This is consistent with the Guide, which states that where the facts of a defence are peculiarly within the defendant’s knowledge, it may be appropriate for the burden of proof to be placed on the defendant.

A legal burden has not been placed on the defendant; if the defendant discharges its evidential burden, the prosecution will still be required to disprove the matters raised by the defendant beyond reasonable doubt.

In terms of the right to the presumption of innocence as afforded to individuals, the reality is that in the offshore regulatory regime investigations and prosecutions are conducted largely if not solely in relation to companies, not individuals. Prosecutions to date have only been in relation to companies, and it is not anticipated that this regulatory approach would change in the future given the nature of the industry and the requirements imposed.

The right to privacy and reputation

The amendments in Schedule 1 to this Regulation that require an environment plan to contain contact details for the titleholder’s nominated liaison person (regulation 15), and that require the Regulator to publish those contact details (subregulation 9(8), subregulation 11(4) and regulation 20A), may engage the right to privacy and reputation in Article 17 of the ICCPR as the contact details are personal information. Article 17 prohibits arbitrary or unlawful interference with an individual’s privacy, family, home or correspondence, and protects a person’s honour and reputation from unlawful attacks. This right may be subject to permissible limitations where those limitations are provided by law and non-arbitrary. In order for limitations not to be arbitrary, they must be aimed at a legitimate objective and be reasonable, necessary and proportionate to that objective.

 

1)      Legitimate objective

The purpose of the relevant provisions is to ensure that there is a specific person, nominated by the titleholder, that the Regulator or members of the public can contact in relation to an activity that is to be, or is being, undertaken in an offshore area. In particular, it provides the Regulator with a person who may be contacted in the event of an emergency.

 

2)      Reasonable, necessary and proportionate response

Under the Environment Regulations as previously in force, contact details for an operator’s nominated liaison personnel were already required to be published. This requirement has been continued; however the requirement now relates to a titleholder’s nominated liaison person, to reflect the transfer of responsibility for compliance with the Regulations from the operator to the titleholder.

Provision of contact details for the titleholder’s nominated liaison person to the Regulator will ensure the Regulator has a single point of contact to discuss matters relating to an activity or the environment plan for that activity. This is particularly important in the event that an urgent circumstance has arisen, such as an emergency, which requires the Regulator to be able to contact the titleholder quickly.

Publication of the contact details will enable persons to engage with the titleholder in relation to an activity, in particular if they have any questions about the activity. This will help to increase transparency in relation to operations undertake in offshore areas.

The information that is required to be provided and published is business-related only. For example, a business address for the liaison person is required to be provided, rather than the person’s residential address.

In addition, the use or disclosure of any information that is personal information is subject to the Privacy Act 1988. Accordingly, the requirement to provide and publish contact details pursuant to the relevant provisions is reasonable, necessary and proportionate in the circumstances.

Conclusion

The Regulation is compatible with human rights because, to the extent that it may limit human rights, those limitations are reasonable, necessary and proportionate.

 


 

 

 

National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA)

 

Strategic Assessment Review Taskforce

 

Single Stage Regulation Impact Statement (RIS)

 

OBPR Reference: 16191


 

Context

1.1.             In 2013, the Government made an election commitment to streamline environmental approvals by delivering a “one-stop-shop for environmental approvals ensuring projects can commence as soon as possible but without compromising environmental standards.”

1.1.1.        The Government proposed that NOPSEMA would be the sole, designated assessor for environmental approvals within its jurisdiction.[1] This includes offshore petroleum and greenhouse gas storage activities in Commonwealth waters and designated waters where powers have been conferred.

1.1.2.        The Government also proposed the establishment of a ‘one-stop-shop’, administered by State and Territory governments for onshore environmental approvals. This is being progressed separately through the Council of Australian Governments.

1.1.3.        This Regulatory Impact Statement (RIS) is relevant only to implementation of streamlining environmental approval processes in Commonwealth waters, and designated waters where environmental management powers have been conferred to NOPSEMA.

1.2.             NOPSEMA was established as an independent statutory authority by the OPGGS Act on 1 January 2012.

1.2.1.        A Commonwealth Government agency, NOPSEMA is the regulator of environmental management law under the OPGGS Act.

1.2.2.        Its jurisdiction covers Commonwealth waters and, where the relevant State or Territory has conferred powers to it, designated (State/Territory) waters. Currently, no environmental management powers have been conferred to NOPSEMA.

1.2.3.        It is the regulator for occupational health, environment and safety and well integrity of petroleum activities, and has the delegated functions for regulation of environmental management of greenhouse gas storage activities.

1.3.             On 25 October 2013, the Minister for Industry, the Hon. Ian Macfarlane MP, the Minister for the Environment, the Hon. Greg Hunt MP, and the CEO of NOPSEMA, Ms Jane Cutler, (the Parties) agreed to undertake a Strategic Assessment under Part 10 of the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act) of the offshore petroleum and greenhouse gas environmental management authorisation process.

1.3.1.        The Parties entered into a formal Strategic Assessment Agreement, as provided for under s146 of the EPBC Act, as a means to implement the Government’s election commitment to establish NOPSEMA as the sole designated assessor for offshore environmental approvals.

1.3.2.        The Department of Industry established an Offshore Environmental Streamlining Taskforce (the Taskforce) consisting of officers from the Departments of Industry and Environment, NOPSEMA, and technical support from industry and academia, to undertake the Strategic Assessment.

1.4.             The Strategic Assessment includes three key documents:

1.4.1.        The Program Report: which describes NOPSEMA’s environmental management authorisation process and commitments in relation to matters protected under Part 3 of the EPBC Act (the Program);

1.4.2.        The Strategic Assessment Report: which provides an assessment of how the Program delivers equivalent environmental outcomes to those achieved under the EPBC Act (the Strategic Assessment); and

1.4.3.        The Supplementary Report: documenting public consultation undertaken in the course of the Strategic Assessment process.

1.5.             At the conclusion of the Strategic Assessment, the Minister for the Environment will consider whether to endorse the Program under the EPBC Act, and then whether to approve classes of actions undertaken in accordance with the Program.

1.5.1.        The Minister for the Environment will decide whether to endorse the Program by mid February 2014, and approve classes of actions by 28 February 2014.

1.5.2.        If the Minister endorses the Program and approves classes of actions, NOPSEMA will be the sole designated assessor for offshore petroleum activities undertaken in its jurisdiction. This will deliver on the Government’s election commitment (Paragraph 1.1.1 refers).

1.6.             The offshore petroleum and greenhouse gas environmental management authorisation process described in the Program is administered by NOPSEMA under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGGS Act) and the Offshore Petroleum and Greenhouse Gas Storage (Environment) Regulations 2009 (OPGGS(E) Regulations).

1.6.1.        The Program describes the OPGGS(E) Regulations as proposed for amendment to implement streamlining reforms. This regulatory model proposed was developed by the Taskforce and agreed by officials on 13 November 2013 at the second meeting of the Streamlining Offshore Petroleum Environmental Approvals Steering Group.

1.6.2.        The Taskforce is also implementing the outcomes of the Government’s 2012 review of the OPGGS(E) Regulations to ensure they represent leading practice for objective-based environmental management regulation. This includes changes to the OPGGS(E) Regulations.

1.6.3.        This RIS is relevant only to changes in regulation required as a consequence of the streamlining exercise.  The Department has engaged separately with the Office of Best Practice Regulation (OBPR) on implementation of the 2012 review of the OPGGS(E) Regulations  (OBPR ID: 2013/16159 refers).

1.7.             Detailed information regarding this Strategic Assessment process under Part 10 of the EPBC Act and amendments to the OPGGS(E) Regulations, including the draft Program Report, draft Strategic Assessment Report and draft regulations released for consultation in November/December 2013, is available at www.industry.gov.au/streamlining.

Element 1   ̶   Assessing the Problem

1.8.             As at 1 January 2014, there are over 400 active petroleum titles in Commonwealth waters. A title gives the titleholder the exclusive right to apply to undertake petroleum activities.

1.8.1.        For the purposes of this RIS, it is assumed there are 61 businesses currently conducting petroleum activities in Commonwealth waters. It is further assumed that an average of 72 offshore petroleum activities take place per year. These assumptions are based on information from NOPSEMA and the Department of Environment for the level of activity in the sector over the past five years.

1.9.             It is difficult to quantify the number of petroleum activities that take place every year, as such activities often form part of larger projects. However, it is possible to provide an indication by quantifying the number of environment plan submissions to NOPSEMA, and the number of referrals submitted to the Department of the Environment under the EPBC Act. It should be noted that in many cases an environment plan or referral will apply to more than one petroleum activity, and the scope of each may not be the same, making direct comparison difficult.

1.9.1.        Over the past 5 years, using information provided by NOPSEMA and the Department of the Environment, it is estimated that there was an average of 70 exploration activities per year, and 2.4 development activities per year.

1.10.         The Australian petroleum industry is a significant contributor to the Australian economy. Total assets exceeded $220 billion in 2011/12. The industry contributed almost $9 billion in taxes, excise and royalties on revenue of just over $38 billion in 2011/12.[2]  Investment in the Australian petroleum industry averaged $35.6 billion per year over the past four years.[3] Investment in the offshore oil and gas sector accounts for a large proportion, but not all of that investment. The onshore gas sector, including the export facilities in Queensland, is also active, with capital projects over that time. Exact figures of capital expenditure in the offshore area are difficult to determine. However, a reasonable figure for average annual investment in the offshore oil and gas sector over the past four years, when accounting for the actual investment over that period on current projects (such as Gorgon, Wheatstone, Icthys, Pluto, Prelude etc) would be in the order of $26 billion per year.

1.10.1.    The industry in Australia comprises a broad range of companies, from small local and regional exploration firms to large Australian companies such as Woodside and BHP Billiton, and medium to large international companies such as INPEX, Osaka Gas, Total, Apache, Chevron, Shell and BP. Commonly, these companies enter into ‘joint venture’ arrangements for exploration and development of offshore resources due to the size of investment required to operate in Australia.

1.10.2.    Small, medium and large firms undertaking exploration and development activities in areas where there is the potential to impact on matters of national environmental significance may be subject to both processes.

1.11.         There is duplication in the development, assessment, approval, compliance, monitoring, reporting and enforcement of the environmental impacts of offshore petroleum activities in Commonwealth waters.  This duplication has resulted because there are two separate, but overlapping schemes that currently apply:

1.11.1.    If a proponent is seeking to undertake an offshore petroleum and greenhouse gas activity, they must prepare an Environment Plan for assessment and authorisation under the OPGGS Act and the OPGGS(E) Regulations.

1.11.2.    In addition, there is an onus on proponents to ensure that their activities are not in breach of the provisions of the EPBC Act. If an activity is likely to have a significant impact on matters of national environmental significance or another EPBC Act protected matter (e.g. Commonwealth Land), the proponent must ‘refer’ the activity to the Department of the Environment for a decision as to whether it is a controlled action and, if it is, approval from the Minister for the Environment under the EPBC Act. This requires a separate referral and assessment process.

1.11.3.    The nature of activities includes, but is not limited to, seismic surveys, exploration and production drilling, facility construction and operation (i.e. for petroleum extraction), and decommissioning.

1.12.         Where a proponent has referred an activity to the Department of the Environment, four outcomes may result. The Minister for the Environment or his/her delegate:

1.12.1.    Determines the activity will have a significant impact on a protected matter, deems it a “controlled action”, and further assessment under the EPBC Act is required before approval. If approved, conditions may (and commonly) apply to that approval.

1.12.2.    Determines the activity will not have a significant impact on a protected matter, deems it a “not controlled action”, and no further assessment under the EPBC Act is required.

1.12.3.    Determines the activity will not have a significant impact on a protected matter, deems it a “not controlled action: particular manner”, and no further assessment under the EPBC Act is required as long as the activity is undertaken in accordance with the conditions (“particular manner”).

1.12.4.    Determines the activity is clearly unacceptable and cannot proceed.

1.13.         In the first three cases, regardless the Department of the Environment’s decision and conditions, proponents must also prepare an Environment Plan for every activity for submission, assessment, and acceptance by NOPSEMA under the OPGGS(E) Regulations. Proponents must then comply with the Environment Plan, as well as any conditions placed on an EPBC Act approval and any prescribed “particular manners” conditions. This may also result in inconsistencies in regulatory requirements (paragraph 1.16 refers).

1.14.         The figure below, sourced from the 2009 Productivity Commission Review of Regulatory Burden in the Upstream Petroleum (Oil and Gas) Sector (the 2009 PC Review) demonstrates the complexity and confusion that also results from the application of two regulatory regimes for the sector.

Figure 1 – Environmental Approval Processes

Figure sourced from 2009 Productivity Commission Review of Regulatory Burden on the Upstream Petroleum (Oil and Gas) Sector.

1.15.         The form and detail of information required for an environment plan (set out in the OPGGS(E) Regulations) and a referral to the Department of the Environment (set out in guidelines and policy documents under the EPBC Act) are similar.

1.15.1.    Both include a description of the environment, the potential impacts and risks that the proposed activity may pose to the environment, avoidance and mitigation measures that the proponent proposes to employ to minimise those impacts, contingency plans in the event of an incident (i.e. oil spill) as a result of the activity, and details on remediation of the environment both in the event of a spill and following completion of the activity.

1.15.2.    These processes are similar, but not identical, and the regulator for each is different, with NOPSEMA regulating the process under the OPGGS(E) Regulations and the Department of the Environment regulating the process under EPBC Act, resulting in inconsistency of expectations and assessments. Industry stakeholders have indicated in consultation that there is duplication of effort to prepare documents and in liaising with regulators to provide context and detailed understanding as well as to amend documents in order to achieve approval (where appropriate).

1.16.         Industry stakeholders have identified inconsistency in regulatory requirements and conditions as a particular issue. As noted in paragraph 1.13, conditions may be placed on decisions and approvals under the EPBC Act, and those conditions may be inconsistent with requirements that apply under the OPGGS(E) Regulations. This has, for example, resulted in inconsistent regulatory requirements for oil spill contingency planning.

1.16.1.    A common approval condition under the EPBC Act is for a company to prepare an oil spill contingency plan (also known as an oil pollution emergency plan), that must be approved by the Minister for the Environment, or at the very least must meet certain standards that are prescribed in the condition.

1.16.2.    At the same time, all companies are required to prepare an oil spill contingency plan under the OPGGS(E) Regulations in accordance with specific criteria laid out in those regulations.

1.16.3.    Industry feedback indicates that the requirements prescribed in EPBC Act conditions are not consistent with the OPGGS(E) Regulations. As a result, companies must prepare two documents in relation to oil spill contingency planning for two different regulators, causing confusion and with potential consequences in the event of an incident if there are inconsistencies in compliance requirements. 

1.16.4.    Industry has also advised that “particular manner” determinations have also required the proponent to prepare oil spill contingency plans. While these requirements require approval by the relevant authority (NOPSEMA), industry reports cases where the requirements also detail particular contents for the oil spill contingency plan which may contradict subsequent OPGGS(E) Regulations.

1.17.         The impact of duplication between these regimes, and in particular inconsistent regulatory requirements, such as the example above, means that companies must meet separate ongoing compliance standards and reporting requirements.

1.17.1.    As the terms of an environment plan decision under the OPGGS(E) Regulations and EPBC Act decision are not identical, there is burden on industry in ensuring compliance with and reporting against both.

1.17.2.    Reporting requirements under the OPGGS(E) Regulations require monthly reporting of general monitoring and annual reports against performance against outcomes and commitments made and approved in an environment plan in relation to discharges and impacts of the activity on the environment. Under the EPBC Act, reporting requirements are commonly outlined in conditions to decisions and relate to monitoring of the environment to ensure the activity is not having an unacceptable impact.

1.17.3.    While these reporting requirements are not identical, they overlap in many regards for a large majority of projects and present a burden of reporting on similar or identical primary source data in different ways to meet the expectations of both regimes.

1.18.         The 2009 Productivity Commission Review of Regulatory Burden on the Upstream Petroleum (Oil and Gas) Sector (the 2009 PC Review) identified and described this overlap between schemes, noting that they can result in duplication of regulatory requirements. The Review notes two reasons for which this is an unnecessary burden:

1.18.1.    First, very few referrals under the EPBC Act require further assessment – Department of Environment data provided to the Taskforce indicates that 177 exploration activities in Commonwealth waters have been referred under the EPBC Act. Of these, only one was found to be clearly unacceptable.  Of the remaining 176 referrals, 153 were deemed not to require assessment, 17 were withdrawn prior to any decision, and six required assessment under the EPBC Act. Of those six, four were withdrawn and one submission lapsed. One was assessed and approved.

1.18.2.    Despite the low incidence of activities that require assessment, companies must consider whether they need to refer these activities to the Department of the Environment to ensure that they will not be in breach of their requirements and proceed with the projects. Based on data provided by NOPSEMA for the last two years, it is estimated that 20 per cent of activities are currently referred.

1.18.3.    Second, industry participants reported to the Productivity Commission that the level of detail and requirements under the OPGGS(E) Regulations to prepare, comply with and report against an environment plan, were sufficient for the petroleum regulator to assess potential environmental impacts. These participants suggested that it was unnecessary to require involvement of the Environment Portfolio as well as the OPGGS(E) Regulations as there was no additional benefit to the environment.[4] 

1.19.         The findings of the 2009 PC Review have been supported by subsequent independent reviews, including the Independent Review of the EPBC Act and the Report of the Montara Commission of Inquiry and the 2013 Productivity Commission Research Report - Major Project Development Assessment Processes (2013 PC Report).

1.19.1.    The Independent Review of the EPBC Act (the Hawke Review), released in 2011, examined ways to reduce and simplify the regulatory burden on people, businesses and organisations, while maintaining appropriate and efficient environmental standards. It noted that there are significant interactions between the EPBC Act and the OPGGS(E) Regulations and recommended the Australian Government consider streamlining the relationship  between the OPGGS(E) Regulations and the EPBC Act to maximise regulatory efficiency while retaining strong environmental safeguards.

1.19.2.    The 2010 Report of the Montara Commission of Inquiry[5] and the draft 2013 Productivity Commission Report on Mineral and Energy Resource Exploration[6] also recommended that the Government streamline these regimes.

1.19.3.    The 2013 PC Report noted that the building blocks of a sound regulatory system are already in place in Australia. The Commission went on to note there is still substantial scope to improve Australia’s development assessment and approval processes. The Commission points to this offshore streamlining project as a noteworthy example of how regulators within the same jurisdiction can cooperate on assessment and approval matters.[7]

1.20.         As noted in the 2009 and 2013 PC Reviews, regulatory delays can have a significant impact as companies commonly seek regulatory approval under the EPBC Act for development projects before making final investment decisions. These approvals therefore directly impact on a company’s decision whether to proceed with the project, and when.

1.20.1.    The industry body, the Australian Petroleum Production and Exploration Association (APPEA), supports and has advocated this through member surveys, studies and submissions to various government reviews in relation to regulatory burden associated with environmental assessment, approval, compliance and reporting processes.

1.21.         APPEA is the peak national body representing Australia’s oil and gas exploration and production industry. It has more than 80 full member companies across the offshore and onshore sector, accounting for an estimated 98 per cent of Australia’s petroleum production. It also represents more than 250 associate member companies that provide goods and services to the oil and gas industry.[8]

1.21.1.    In September 2008, in a submission to the Productivity Commission, APPEA noted duplication between the two regimes and suggested the Commonwealth Environment Minister recognise the environmental assessments under the OPGGS Act, especially for exploration activities. APPEA’s submission noted, in particular:

·         “Each year the industry drills, on average, around 60 new exploration wells, refers a majority for assessment under the EPBC Act and for all but a few since the commencement of the Act, has received a “not controlled” determination” – meaning assessment was not required.[9] 

1.21.2.    More recently, in its 2013 public report Cutting Green Tape – Streamlining Major Oil and Gas Project Environmental Approvals Processes in Australia (Green Tape Report), APPEA argued duplicative and overlapping environmental regulatory requirements can threaten the full potential of economic returns to the community from this sector through project delays, uncertainty and the foregoing of market windows and investment opportunities[10].

1.21.3.    APPEA also noted regulatory compliance costs can substantially impact on cash flows leading to some marginal activities becoming unviable or ceasing to operate.[11] This is consistent with the 2009 PC Review’s findings that unnecessary approvals costs add to the existing barriers for entry of smaller companies into the petroleum sector, potentially reducing opportunities for competition and innovation[12] and the impetus for development delivered by exploration activities.

1.22.         APPEA’s submission to the Taskforce[13] notes its support for “the Government’s commitment to create a ‘one-stop-shop’ for offshore petroleum environmental assessments” and that “the Draft Strategic Assessment Reports are therefore a significant step in the right direction.” The Productivity Commission in its 2013 report on Major Project Development Assessment and Approvals pointed specifically to the offshore streamlining Strategic Assessment as an example of good co-operation between regulatory agencies.

1.23.         The current regime poses a burden not only on the oil and gas industry, but also on key stakeholders that interact with that industry, particularly in the course of consultation on relevant environmental management plans and arrangements. These include tourism and fishing operators, and non-government organisations (NGOs) including environmental NGOs.

1.23.1.    In the course of consultation on the streamlining process, several industry and NGO stakeholders noted the regulatory burden of the current regime on other sectors in their interactions with the offshore petroleum industry.

1.24.         The National Seafood Industry Alliance (NSIA) commented specifically on this matter in its submission to the taskforce:

1.24.1.    The NSIA brings together the Commonwealth, National State and Territory peak industry bodies in the Commercial Fishing and Aquaculture industries to provide national representation to the federal government.

1.24.2.    The NSIA’s submission noted that it and its members are “increasingly inundated with information on large numbers of oil and gas sector activities.” The submission provides detailed comments on the proposals, concluding that “to assist in streamlining the approvals process processes, NSIA endorse NOPSEMA as the single independent regulator for these issues.”

1.25.         Environmental NGOs[14] broadly recognised the Government’s commitment and agenda to reduce regulatory burden by streamlining processes, but raised concerns in relation to the policy and whether the proposed arrangements would ensure adequate environmental protection.

1.26.         The Government’s commitment is to streamline processes and reduce regulatory burden while maintaining environmental safeguards. The implementation of this election commitment through a strategic assessment (paragraph 1.32 refers) will therefore ensure that the same level of environmental protection will be achieved. In addition, while the definition of the environment is consistent between the EPBC act and the OPGGS(E) Regulations,  the amended OPGGS(E) Regulations will now include an explicit reference to matters of national environmental significance.

1.27.         It is not clear that the current situation, where two regulatory regimes apply, provides additional environmental protection or benefits compared with the proposed system where only the OPGGS(E) Regulations apply. Further, the benefits of reducing regulatory overlap and duplication is one obvious source of unnecessary burden for proponents of major projects. The Productivity Commission notes that the size of the costs caused by delays to major projects points to potentially substantial gains if efficient ways to save time can be found.[15] 

1.27.1.    Industry feedback  suggests there are cases where conditions applied under EPBC Act approvals or decisions that an activity may proceed in a “particular manner” is that these requirements impose obligations without resulting in improved environmental outcomes (paragraph 1.16 refers).

1.27.2.    The OPGGS(E) Regulations are broader in scope in that they apply to all impacts and risks on the environment, and not just significant impacts or risks on particular matters in the environment.

1.27.3.    The OPGGS(E) Regulations applies the same fundamental test of whether potential impacts and risks to the environment are “acceptable” before an activity may proceed.

1.27.4.    The Strategic Assessment, and Strategic Assessment Report identifies in detail how the OPGGS(E) Regulations provide for the protection of the relevant matters identified in the EPBC Act to ensure that the streamlining exercise improves the efficiency of the regime while maintaining the same environmental outcomes.

 

Element 2   ̶   Objectives of Government Action

1.28.         The Government’s intent is to streamline existing environmental approvals of offshore petroleum and greenhouse gas storage activities in Commonwealth waters, as well as in designated State or Territory waters where those jurisdictions’ powers have been conferred to the Commonwealth and to make NOPSEMA the sole designated assessor for these activities, in line with the Government’s 2013 election commitment (paragraph 1.1 refers).

1.29.         In line with this objective, this proposal aims to provide greater certainty for business, accelerate approval times and support investment decisions and Australia as an attractive investment destination while ensuring strong environmental safeguards are retained that both ensure:

1.29.1.    Offshore petroleum activities are carried out in a manner consistent with the principles of ecologically sustainable development.

1.29.2.    Protection of matters under Part 3 of the EPBC Act.

1.30.         This proposal also aims to contribute to the Government’s deregulation policy agenda and its commitment to reduce regulatory burden for individuals, business and community organisations by $1 billion per year.

Element 3   ̶   Options that may achieve the objectives

1.31.         In October 2013, the Government decided to undertake a Strategic Assessment of NOPSEMA’s environment management authorisation process to achieve its election commitment to streamline approvals in Commonwealth waters and, where the relevant jurisdiction has conferred powers, in designated (State and Territory) waters.

1.31.1.    The 25 October 2013 Strategic Assessment Agreement (paragraph 1.3 refers), signed by the Minister for Industry, the Minister for the Environment, and the CEO of NOPSEMA, affirms this decision.

1.32.         A Strategic Assessment is a statutory process authorised by the EPBC Act (Part 10 of the EPBC Act refers). The process, as set out in the EPBC Act, is a broad assessment, as opposed to a case by case assessment, that in this case will assess the impacts of NOPSEMA’s processes against the standards and requirements of the EPBC Act.

1.32.1.    The purpose of a strategic assessment is to provide the Minister for the Environment with information to make two decisions: to endorse a policy, plan or program (in this case ‘the Program’ which describes NOPSEMA’s processes); and to approve certain actions or classes of actions (in this case offshore petroleum and greenhouse gas activities).

1.32.2.    The Minister for the Environment must not endorse NOPSEMA’s processes or approve actions unless the Strategic Assessment meets the requirements under the EPBC Act. This process delivers the same level of environmental protection under the NOPSEMA process as that achieved under the EPBC Act.

1.33.         The Minister for Industry and the Minister for the Environment will make the final decisions regarding implementation of this reform in February 2014.

1.33.1.    The Minister for Industry will decide whether to approve the amendments to the OPGGS(E) Regulations

1.33.2.    The Minister for the Environment will decide whether to endorse the Program, to be implemented by NOPSEMA including through the OPGGS(E) Regulations, and whether to approve actions taken in accordance with the Program, effectively removing the requirement for companies to seek EPBC Act approval for offshore petroleum activities.

1.34.         On 15 November 2013, the OBPR advised the Taskforce in writing that a RIS would be required for the “Streamlining Offshore Petroleum Environmental Approvals”.  The OBPR further advised a single stage, single option details RIS focusing on delivering on the government’s election commitment would be acceptable.

1.35.         In accordance with this advice, and in accordance with section 7.86 of the OBPR Handbook (July 2013):

1.35.1.    The agency has prepared a single-stage RIS, and as no decision has been previously announced, an options-stage RIS is not required.

1.35.2.    As this is a single stage RIS, the checklist (which is in relation to an options-stage RIS) is not relevant and has not been included.

Description of proposal

1.36.         The Program (paragraphs 1.4.1 and 1.6.1 refer) will replace the current dual approvals system. It will apply to all offshore petroleum and greenhouse gas activities authorised in the OPGGS Act and undertaken in Commonwealth waters, as well as designated waters where powers have been conferred to NOPSEMA. 

1.36.1.    This will benefit over 60 oil and gas companies, as well as all other stakeholders who interact with those companies in relation to the petroleum activities in Australia.

1.37.         The Program is comprised of two environmental assessment paths: the Environment Plan (EP) and Offshore Project Proposal (OPP).

1.38.         Titleholders are already required to submit an EP for assessment and acceptance by NOPSEMA prior to commencing any offshore petroleum or greenhouse gas storage activity. The activity must not commence unless NOPSEMA has accepted the EP.  This requirement remains unchanged.

1.39.         The OPP will be introduced in the OPGGS(E) Regulations.  It will capture development projects that may have an impact on a matter protected under Part 3 of the EPBC Act and would otherwise have been a controlled action and subject to assessment processes under the EPBC Act.

1.39.1.    The OPP process can be used for all petroleum activities, but will only be mandatory for development activities (as per the definition of ‘offshore project’ in the proposed regulations – see item 23 in the Exposure Draft). Generally, development activities that would currently be subject to EPBC assessment will undergo OPP assessment instead.

1.39.2.    It will not be mandatory to submit an OPP for exploration and other non-development activities. As many exploration activities currently undergo EPBC Act assessment, this will be a saving to industry. Exploration and other non-development activities will continue to require an approved EP to proceed.

1.39.3.    An Offshore Project Proposal will be required for all new development activities that do not have a prior EPBC Act decision under Parts 7 or 9. Additional or new stages of existing developments will not be subject to the mandatory Offshore Project Proposal provisions, but will require an accepted Environment Plan in place before any new stage of an activity can commence.

1.40.         This means, for development activities, proponents will no longer need to consider whether an activity may have a significant impact, and will not have to refer the proposed activity to the Department of the Environment under the EPBC Act. Instead, proponents will need to prepare and submit an OPP to NOPSEMA for assessment, to demonstrate that impacts and risks to the environment will be acceptable.

1.41.         This means, for exploration activities, proponents will no longer need to consider whether an activity may have a significant impact, and will not have to refer the proposed activity to the Department of the Environment under the EPBC Act. Proponents will not need to prepare or submit an OPP.

1.42.         For both development and exploration activities, proponents will need to prepare and submit an EP to NOPSEMA (as is currently the case), which will need to demonstrate that impacts and risks to the environment are reduced to as low as reasonably practicable, and are acceptable.

1.43.         The EP process will ensure there is no unacceptable impact to the environment as a result of the proposal. EPs (and OPPs) are developed under an ‘objective-based’ regulatory regime for environmental protection. 

1.43.1.    Objective-based regulation places the onus and duty of care for environmental protection on proponents seeking to undertake an offshore petroleum activity. This is not self-regulation by industry, as industry must demonstrate to NOPSEMA – and NOPSEMA must assess and accept or not accept – that it has reduced the risks of an impact to as low as reasonably practicable. These environmental impacts and risks must also be of an acceptable level.

1.43.2.    The outcome of an objective based regime is that proponents consider the costs and implications to the environment as part of their investment decisions. In this regard, objective-based regulation encourages continuous improvement rather than minimum compliance. It ensures flexibility in operational matters to meet the unique nature of different projects, and avoids a ‘lowest common denominator’ approach to regulation.

1.43.3.    Proponents must consider and identify the acceptable outcomes for all environmental matters, including matters of national environmental significance must be identified, and the activity approved must include a clear demonstration of how those outcomes will be delivered.   This is in contrast to requirements under a prescriptive regulatory regime, where the proponent only takes into consideration those matters specifically identified by the regulation, with the level of investment commensurate to that need to meet the minimum standard of protection the regulator prescribes.

1.43.4.    Objective-based regulation is well established in the regulation of occupational health and safety, and environmental management. It is modelled from international examples, in particular the United Kingdom’s regulatory regime for offshore petroleum, and reviewed periodically. In particular, the independent 2010 Montara Commission of Inquiry reviewed and confirmed the appropriateness of objective-based regulation for the sector.

Element 4   ̶   Impact Analysis

Costs

1.44.         There are two broad groups of costs that have been included when calculating the impact on affected industry participants: costs/savings related to business activities associated with the regulatory regime itself (direct costs); and costs/savings associated with the impact of delay/acceleration of regulatory processes and decisions on project investment timing (delay costs). Each of these matters has been considered in Element 4.

Direct costs    

1.45.         Much of the work associated with preparing an EPBC referral duplicates work undertaken to produce an EP. Some costs are currently shared between the two processes, while others will be saved with the removal of EPBC requirements.  It has been established, in discussions with NOPSEMA and industry participants, that:

1.45.1.    The reports commissioned to produce project specific baseline environmental data and to assess the risks associated with the activity are used in both processes;

1.45.2.    Costs associated with controlled actions for exploration projects will cease, and fall for development projects;

1.45.3.    The compliance costs (e.g. staffing, consultancy etc.) associated with an EPBC Act referral for development projects will fall;

1.45.4.    Travel to Canberra to brief the Department of Environment during the referral assessment process for both development and exploration projects will cease. NOPSEMA offices are located in Perth and Melbourne, both of which are business centres for the offshore oil and gas industry.

1.45.5.    A single regulator will also remove the need for duplicate industry briefing and reduce the risk to industry of divergent understanding of issues between the Department of the Environment and NOPSEMA.

1.46.         The Taskforce has undertaken targeted industry consultation to estimate costs and savings associated with the streamlining reform.  The information provided indicates that clear and substantial savings will be achieved, although the exact savings can be difficult to estimate, and some data is commercial-in-confidence or anecdotal in nature.

1.46.1.    Further information, on assumptions and cost calculation is at Appendix A. This includes:

·       Key general assumptions

·       Costing assumptions

·       Consultation on assumptions

·       Business Cost Calculator (BCC) assumptions

·       Detailed BCC costing and data input explanations

1.47.         Broadly, the proposal will benefit industry and other stakeholders by ensuring there is one regulatory point of contact. Currently, industry and other stakeholders must consult with both NOPSEMA and the Department of the Environment to seek clarification on regulatory requirements, proposed and ongoing activities, and their impacts on petroleum activities on the environment. Under the proposal, NOPSEMA will be the sole regulator for these activities and the single point of contact for industry and other stakeholders, including the public.

1.48.         As NOPSEMA will be the sole regulator for environmental management of petroleum activities, this will also increase consistency in decision-making. As noted above (paragraph 1.16 refers), the current regime allows for and has resulted in inconsistent decision-making, particularly in relation to the specific conditions and requirements placed on proponents.

1.48.1.    Direct feedback from industry in the course of consultation on the impacts for this RIS indicated that such inconsistencies are a concern. Industry stakeholders specifically identified increased consistency in decision-making as a benefit of streamlining.

1.49.         The proposed model will result in a single timeline for environmental assessments, as opposed to the separate timelines that currently occur under the EPBC Act and OPGGS(E) Regulations. For development activities, proponents will need to prepare and submit an OPP before they may submit an EP. These processes are not separate, however. It will be an integrated process over a single timeline as the requirements for an OPP feed into the more detailed requirements for an EP.

1.49.1.    In the OPP for a development project the proponent must, for example, identify environmental performance outcomes and demonstrate that achievement of those outcomes will ensure potential environmental impacts and risks will be acceptable.

1.49.2.    Once the OPP is accepted, the proponent must then, in its EP, build on those environmental performance outcomes, develop an implementation strategy to achieve those outcomes, and demonstrate that risks will be reduced to as low as reasonably practicable as well as acceptable.

1.49.3.    The proposed amendments to the regulations will also provide that proponents do not have to present the same information to NOPSEMA twice. This provision, in addition to synergies in the acceptance criteria for OPPs and EPs, will allow for the integration of assessment processes where appropriate.

1.49.4.    Industry consultation in the course of developing the model supported the premise that there will be benefit and efficiencies through integration of the overall process in this manner, as part of a single timeline.

1.50.         The proposed model will remove the risk of conflicting approval requirements. As noted in paragraph 1.16, and confirmed by industry feedback (paragraph 1.48.1 refers), current arrangements can and do result in conflicting requirements on proponents.

1.50.1.    Under the proposed model, it will no longer be possible to place EPBC Act decision and approval conditions on industry, removing the risk of conflict with EP requirements.

1.50.2.    Furthermore, the proposed OPP process does not provide for NOPSEMA to place conditions on approvals. This means it will not be possible to place conditions on an OPP that could conflict with an EP.

1.50.3.    Finally, the requirements for OPP and EP are both set out in regulations and have been drafted to ensure consistency, as demonstrated in the exposure draft of the amendment regulations released for public consultation in December 2013. These provisions remain unchanged following consultation, with the exception of an additional requirement that has been added to both (thus maintaining their consistency).

1.51.         The proposed model will also lead to an overall reduction in the costs to industry, government and the community. This is indicated in the analysis of specific compliance cost savings below, which describe the saving to industry and the not-for-profit sector. Generally, however, there will be an overall reduction in costs through:

1.51.1.    Reduced compliance costs for industry (see Table 1 on page 19), and benefits as described above in relation to having a single regulatory point of contact, consistent decision making, an integrated assessment timeline and no further risk of conflicting approval requirements. Feedback from industry in developing the proposal, during the public consultation process (refer to Consultation section below) and in determining compliance costs supports this view.

1.51.2.    Reduced cost and imposition on the community, including the not-for-profit sector, primarily in relation to having a single regulatory point of contact in relation to environmental management for offshore petroleum, but also in relation to streamlined consultation processes with industry (paragraph 1.76.2 refers). Feedback from non-industry stakeholders has indicated there will be cost benefits in streamlining processes. However, environmental stakeholders also expressed a preference to retain the current burden rather than remove EPBC Act requirements.

1.51.3.    Reduced administrative costs to government associated with savings in administrative costs in EPBC Act assessments. Costs of OPP assessment will be fully cost recovered through a cost recovery fee on industry. EP assessment and compliance is already fully cost recovered through cost recovery levies.

Delay costs

1.52.         More broadly, the proposed model will increase business certainty and confidence. In consultation during the preparation of this RIS, industry participants have advised that the largest benefit for industry will be an increase in the certainty and confidence in the process, as well as the reduction in timeframes for major environmental approval.

1.53.         The cost of delay in the offshore oil and gas sector varies significantly across projects and activities. Several reports have undertaken calculations to estimate the impact of a delay on a project. The 2013 PC Report, notes that “…. the size of the costs caused by delays to major projects points to potentially sizeable gains if efficient ways to save time can be found”.   The report goes on to note that cost estimates relating to an unnecessary delay are borne by the project proponent (from delayed profits) and the wider community (through delayed [and reduced where delay costs are uplifted and credited against future liabilities] royalty and tax revenue). Delay may also result in higher financing and commercial costs.[16]

1.53.1.    Consultation identified timeframes for approval as an average of two months to develop a relatively simple an initial EPBC Act referral and that an environmental impact statement under the EPBC Act likely to result in a 12 – 13 month referral process. It was considered that implementation of the streamlining proposals as suggested in the strategic assessment will reduce these timeframes to a six month process, providing considerable benefit to industry. In consultation, some industry participants suggested time savings in the order of two to three months for the average development project. Others suggested up to six months.

1.53.2.    The Productivity Commission, however, noted that the availability and value of published information about the timeliness of development assessment and authorisation processes is limited.[17]

1.53.3.    Deloitte Access Economics, however, prepared a Cost Benefit Analysis for the then Department of Sustainability, Environment, Water, Population and Communities (DSEWPaC)[18], in which Deloittes calculated a delay figure using data provided by DSEWPaC on the 142 projects that were delayed due to late decisions by DSEWPaC. Deloittes’ analysis showed that these delays ranged from only one day (10 per cent) to over a year (one per cent), with an average delay of around one month (22.7 business days). Deloittes went on to note that it is generally not small projects that are delayed.[19]

1.53.4.    Several proponents also noted that streamlining of environmental approvals is expected to reduce overall burden on companies to free up resources for other business processes, including occupational health and safety. 

1.54.         Streamlining environmental approvals is expected to enhance Australia’s profile as an attractive investment destination. Industry feedback indicates that the increased certainty that comes with having a single environmental regulatory regime will support improved project scheduling, procurement processes, and reduce contracted risk.  Several proponents also noted the reform will mean they are better able to demonstrate the value of a project to both management and key investment partners. 

Costs estimated using the Business Cost Calculator

1.55.         The following discussion addresses specific compliance costs within the scope of the BCC.

1.56.         Using the BCC, the inferred compliance saving from this streamlining reform is an annual average $10.3 million across all offshore project types. Table 1.1 describes the average annual administrative and substantive compliance costs that contribute to the total average annual compliance cost savings.

1.56.1.    The expected annual average compliance costs savings associated with not requiring an OPP for exploration activities is $8.4 million. This is a saving for industry as these activities will no longer require referral, assessment or approval under the EPBC Act.

Table 1.1: Average annual change in compliance costs[20]

Sector / Cost categories

Business

Not-for-profit

Individuals

Total by cost category

Administrative costs

–$8,359,697

–$668,276

–$9,027,973

Substantive compliance costs

–$1, 259,138

–$1,259,138

Total by sector

–$9,618,835

–$668,276

–$10,287,111

1.57.         The expected annual average compliance costs savings associated with the streamlined process were derived by calculating the estimated saving to business, both in terms of direct costs and the costs of delays to investment (paragraph 1.65.1 refers). This was done by calculating and removing all compliance activities for EPBC Act matters and then re-including those costs associated with the OPP under the streamlined process. A detailed description of how the results were calculated is detailed in Appendix A.

1.58.         In interpreting the RIS, it should be noted that the costs associated with an EPBC Act referral vary considerably. Projects can vary in their scale, complexity, geographical location, the identified environment and type.

1.58.1.    At least one industry participant indicated that the costs for an EPBC Act referral used in the BCC calculations are only a third of the costs they typically incur.  Comments received by some other industry participants indicated that the figures may be low but within the range of costs incurred.

1.58.2.    Industry participants further stated that referral costs tend to be particularly significant where particular manner decisions generate controls that are placed on the project after the referral has been submitted, that are not industry standard for perceived impacts to matters of national environmental significance.

1.59.         In calculating the figures, the Taskforce sought costs information from industry that took into account labour costs (i.e. number of staff required for a task, time taken to prepare various reports and submissions, $/hr), economic, and other costs including on-costs, travel costs, consultancy fees and the costs associated with the requirement for wider consultation with stakeholder to be undertaken.

1.59.1.    It is also the noted that for offshore activities the costs are typically higher than those incurred for an equivalent activity onshore[21] due to factors such as access and engineering challenges, and this may result in higher values being reflected in some cost categories. 

1.60.         The projected savings apply across the oil and gas sector, demonstrating an overall reduction in compliance costs and burden as a result of streamlined regulatory processes. Particular activities or activity types may experience a greater or lesser saving. As noted by industry peak body APPEA in the course of consultation, there is significant varying in the scale and location of offshore petroleum activities in Australia.

1.61.         The not-for-profit sector will also benefit from streamlined arrangements. The associated savings arise from the removal of duplicative consultation and submission processes under two separate regulators. As discussed in 1.51.2, a single regulator also provides a single point of contact and information for parties with an interest in offshore environmental regulation. The benefits to the not-for-profit sector are estimated at $670,000 per annum.

1.61.1.    The assumptions used to calculate the estimated saving to the not-for-profit sector were supported as being reasonable in consultation. However, an environmental NGO highlighted that this should not be interpreted as an endorsement of the policy reform more broadly.

Delay costs calculation

1.62.         The delay costs/savings associated with an accelerated assessment and approvals process was calculated on two component inputs: 

1.62.1.    An average delay/acceleration of 27.7 business days (11.1 per cent of a business year) was adopted. Although this is slightly higher than the average delay calculated by Deloittes (see paragraph 1.53.3)[22], it better reflects feedback received from industry.

1.63.         In its 2013 research report on Major Project Development Assessment Processes, the Productivity Commission analysed the indicative costs of a one-year delay to an offshore Liquefied Natural Gas (LNG) project.  In doing so, the Productivity Commission used a discounted cash flow methodology and data sourced from several stakeholders, including the Australian Petroleum Production and Exploration Association, who supplied data for output volumes, and construction, operating and decommissioning costs. The project cash flows were discounted to the present day using an assumed cost of capital (i.e. discount rate) of 8–12 per cent per year.

The illustrative project modelled by the Productivity Commission assumed construction costs of $11.3 billion. It is worth noting that, contrary to the Productivity Commission’s advice that this amount reflects an investment size commensurate with the large projects currently being developed in the sector, it is more likely at the lower end of the ‘large project’ scale, particularly given the following:

Project

Construction Costs

Gorgon

+ $55 billion

Icthys

+ $35 billion

Wheatstone

~ $29 billion

 

1.64.         The cost of a delay for an offshore LNG project can be measured by the impact on its net present value (NPV); a cost that is borne by the project proponent (from delayed profits) and the wider community. The Productivity Commission’s analysis shows that the NPV of the project analysed ranged from $7 billion to $19.8 billion, depending on the assumptions used. A delay to the project could see a reduction in the projects NPV of between $0.5 and 2.0 billion respectively for a one year delay.

1.64.1.    The Department of Industry has used actual project data to test the results of the Productivity Commissions’ modelling. While a similar discount rate of 10 per cent was used, output volume, cost data, and ultimately the NPV of the project differ from that analysed by the Productivity Commission. The Department of Industry observed that despite these differences, there was a similar impact on the projects NPV, approximately 10 per cent as opposed to the Productivity Commissions 9 per cent, resulting from a one year delay.

1.65.        

Calculating the economic costs of regulatory delay

The Productivity Commission calculated that a one-year delay to a major offshore LNG project could reduce its net present value (NPV) by between $0.5 and 2.0 billion. Given the size of the LNG projects currently being developed in the sector, the Taskforce has determined that it is more appropriate to estimate the economic cost of regulatory delay using a reduction in NPV estimate of $1.8 billion (at the upper end of the Productivity Commissions estimates, noting that the project analysed is comparatively small to those currently being progressed).

Using the Productivity Commission’s analysis and assuming there will be an average of 3 projects per year, the delay cost of 1 year would be:

3*$1.8 billion or $5.4 billion

Industry discussion has suggested that streamlining could potentially reduce the time for an assessment by between 2 and 3 months. The Deloittes analysis, based on a wide range of onshore and offshore projects, including urban development, infrastructure, mining and gas sectors, suggested 22.7 business days as the average delay time. The Taskforce has taken a more conservative approach than that of industry, while noting the Deloittes analysis, and adopted 27.7 business days as the average timesaving. The basis for Delloittes’ empirical evidence is set out at paragraph 1.53.3.

Accordingly, the $5.4 billion has been reduced in line with the reduction in time. 27.7 business days as a proportion of the business year (calculated by Deloittes as 250 business days, after allowing for weekends and public holidays) is 11.1 per cent.  Applying this reduced time saving to the $5.4 billion results in a cost associated with a delay of 27.7 days as follows.

$5.4 billion*11.1 %  = $598,320,000

The Taskforce has been cautious in suggesting that all investments will benefit from a shortened approval process. Preferring a conservative approach, the taskforce has assumed that only 50 per cent of investments will benefit from the timesaving. Using the Productivity Commission’s estimates an estimated delay cost saving of:

$598,320,000/2 = $299,160,000

This figure represents the estimated economic costs of regulatory delay for three projects, spread over the life of the projects. It should be noted that the figure of $598,320,000 was that which was applied to the costs calculated at Table 2.

 

 

 
The Department of Industry’s analysis demonstrates that the methodology used by the Productivity Commission is an accurate way of calculating the costs of a one-year delay to an offshore LNG project. The Taskforce has therefore used the Productivity Commission’s central estimate as the basis for determining the savings that could be achieved by reducing regulatory delay. The workings of those calculations follow:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1.66.         It is important to note that these estimates relate to costs borne by the project proponent (from delayed profits) and the wider community (through delayed, and lost where the additional costs are uplifted and offset against royalty and tax revenue). Delay may also result in higher financing costs and commercial risks.

1.67.         In its Submission to the 2013 Productivity Commission Report, the then Department of SEWPaC (now the Department of the Environment), based on a sample of 17 projects of varying type and complexity, found average approval times of 37 months. In most cases, for major projects, most of the assessment time can be attributed to the proponent undertaking studies and preparing assessment documentation. For example, proponents spent an average of 20 months (from an average of 37 months from referral to approval) preparing environmental impact statements and collecting public comments.[23]

1.67.1.    The potential for acceleration in assessment and approvals through streamlining offshore environmental assessments is therefore significant, potentially in the realm of months. Further, the size and nature of offshore development projects, almost all of which are in the tens of billions in capex, means that acceleration of just one project will have significant economic benefits.

1.68.         Table 1.2 includes an estimate of the economic cost of delay over the life of projects, which is dependent on the commencement of three projects each year. The BCC was not used to calculate these costs. Instead, the Taskforce used analysis undertaken by the Productivity Commission.

Table 1.2: Estimate of the economic cost of delay over the life of projects 

Sector / Cost categories

Business

Not-for-profit

Individuals

Total by cost category

Delay costs

–$299,160,000

–$299,160,000

Total by sector

–$299,160,000

–$299,160,000

 

1.69.         The Taskforce has tested the logic, assumptions, and outcomes underpinning these estimated delay costs, as well as the resulting cost estimates, with industry and officers within the Australian Government Bureau of Resources and Energy Economics. These stakeholders have indicated these estimates are reasonable.

1.70.         Exploration delays can also have a significant impact on development projects, as the latter relies on the former. 

1.71.         The Productivity Commission (2009) Review of Regulatory Burden on the Upstream Petroleum (Oil and Gas) Sector noted that the long-run costs associated with a one-year delay in approval of exploration activity were estimated at a 9 per cent reduction in the NPV of an ensuing project.[24]

1.71.1.    However, the exact delay costs associated with exploration projects are difficult to quantify. It is difficult to obtain baseline data to determine the broader impact of a delay in an exploration drilling campaign, for instance due to costs associated with having a drill rig sitting idle at $1 million per day.

1.71.2.    While the delay costs for exploration projects are not quantified, it is important to note that any acceleration of approvals for exploration activities will increase the overall saving to industry.

1.72.         As discussed above, the economic cost of delay/savings for development projects is estimated at $299,160,000 (for three projects over their economic life). It should be noted that this is a conservative estimate.

1.73.To fit within the approach for the government’s broader regulatory reform program the Taskforce was required to adopt the OBPR approach to averaging which applied a straight line average to the $598,320,000 and then summed the first 10 years. This results in an average annual compliance cost, as calculated for the Regulatory Burden and Cost Offset Estimate Table for this Regulatory Impact Statement, of $120 million.  

Table 2: Regulatory Burden and Cost Offset (RBCO) Estimate Table

Average Annual Compliance Costs (from Business as usual)

 

 

 

 

 

Costs ($m)

Business

Community Organisations

Individuals

Total Cost

 

 

 

 

 

Total by Sector

-$119,310,835

-$668,276

$ -

-$119,979,111

 

Cost offset ($m)

Business

Community Organisations

Individuals

Total by Source

Agency

$0

$0

$0

$0

Within portfolio

$0

$0

$0

$0

Outside portfolio

$0

$0

$0

$0

Total by Sector

$0

$0

$0

$0

 

Proposal is cost neutral?

No

 

 

 

Proposal is deregulatory

Yes

 

 

 

Balance of cost offsets

-$119,979,111

 

 

 

 

Risks

1.74.         This streamlining reform will not capture all of the potential benefits.

1.74.1.    Opportunities to capture further benefits from streamlining environmental assessment process between State and Commonwealth waters and for onshore activities remain, particularly for those projects that extend from Commonwealth waters, through State/Territory waters and onshore.

1.74.2.    This streamlining reform provides an important initial step in capturing these additional efficiencies.

1.74.3.    It should be noted that, due to the difficulty in sourcing data and testing the impact of the new process on matters such as the expedition of assessments and approvals, the Taskforce applied a very conservative approach to the cost of delays. The delay cost savings to industry and the community could therefore be significantly understated.  

1.75.         The transition to the new arrangement may also create challenges as participants adjust to the new arrangements.

1.75.1.    Administrative arrangements are currently being established between NOPSEMA, the Industry and Environment Departments to ensure that industry and interested stakeholders are provided effective and efficient guidance and advice. Final arrangements will be in place within six months of endorsement and approval.

1.76.         In addition, industry has noted that the efficiency of NOPSEMA’s internal processes and procedures could be improved.

1.76.1.    This is an area of ongoing reform.  The NOPSEMA Advisory Board provides advice and makes recommendations to the Commonwealth Minister, State and North Territory Ministers and the Standing Council on Energy and Resources (SCER) on the performance by NOPSEMA of its functions and policy and strategic matters.

1.76.2.    The Board also gives advice and recommendations to the Chief Executive Officer of NOPSEMA about operational policies and strategies to be followed by NOPSEMA in the performance of its functions.

Element 5   ̶   Consultation

1.77.         Stakeholder consultation and expertise has been central to the policy and process to develop the proposed model for streamlining.

1.77.1.    The Terms of Reference for the Strategic Assessment was finalised and agreed following four weeks public consultation: in September 2013, officials from the then Department of Resources, Energy and Tourism conducted targeted face-to-face stakeholder consultation with industry, fishing and environmental NGOs, as well as government departments.

1.77.2.    As noted above (paragraph 1.3.2 refers), membership of the Taskforce itself was not restricted to government, and included expertise from the petroleum industry and academia.

1.78.         On 22 November 2013, the Minister for the Environment and the Minister for Industry released the Draft Program Report and Draft Strategic Assessment Report for public consultation. The public comment period was advertised in national newspapers on Saturday 23 November 2013, and submissions closed on 20 December 2013.

1.79.         On 6 December 2013, the Taskforce released an Exposure Draft of amendments to the OPGGS(E) Regulations to implement the Program.  Comments on the draft regulations closed on 20 December 2013.

1.80.         Thirteen information sessions on the Draft Program and Strategic Assessment Reports and the proposed environment regulations were held in Hobart, Melbourne, Adelaide, Perth and Canberra during the weeks of 25-29 November and 9-12 December 2013. A total of 308 individuals representing industry, NGOs, the fishing industry and government attended.

1.80.1.    Invitations for these sessions and regular updates were sent to stakeholders through the Taskforce stakeholder list (approx. 350 subscribers), Australian Petroleum News (approx. 1200 subscribers), and NOPSEMA’s stakeholder information alert system (approx. 880 subscribers). Notices were also published on the Department of Industry, the Department of the Environment, and NOPSEMA’s websites.

1.80.2.    Each session involved a question and answer segment where comments and questions of clarification were put to the Taskforce. Industry sessions focussed on reduction of regulatory burden, while eNGO/government sessions focussed on environmental standards, public interest and transparency.

1.80.3.    The consultations demonstrated broad support for the reform which is seen as a workable model.  Variations in the preferences of individual groups were at the margins of the reform and reflected the spectrum of circumstances and specific interests of the groups represented.  Environmental NGOs’ responses were more conservative, focusing on ensuring continued maintenance of environmental standards.  The need for further information on transition arrangements, compliance and enforcement to support industry’s transition to the new arrangements was also noted and is being addressed by the taskforce.

1.81.         The comments received throughout the consultation process are not expected to result in a significant change to the regulatory model and, as a consequence, are not expected to change the cost analysis outcomes set out in this RIS.

1.82.         A total of 38 written submissions were received by 24 December 2013.  A table outlining stakeholder feedback from information sessions and submissions, and the Taskforce’s recommended response to the feedback, is at Appendix B.

1.82.1.    Major themes identified throughout the submissions include:

·         Environmental protection under the Program;

·         NOPSEMA’s capacity to undertake the commitments in the Program;

·         The decision making process for OPPs and EPs;

·         Consultation and transparency provisions; and

·         Compliance and enforcement provisions.

1.82.2.    Industry stakeholders were broadly supportive of the policy and proposed mechanisms to achieve streamlining of environmental management regulation for offshore petroleum and greenhouse gas storage activities, with most submissions seeking clarification on matters of detail associated with the proposed model.

1.82.3.    Environmental stakeholders raised concerns surrounding the policy and proposed amendments, but also expressed ‘consultation fatigue’ in relation to the burden of being consulted with by the petroleum industry in the preparation of both environment plans and EPBC Act referrals.

1.82.4.    The table at Appendix B describes and responds to all key issues raised in submissions. 

1.83.         Overall, the consultation indicates broad industry stakeholder support for streamlining environmental approvals while maintaining existing environmental safeguards.

1.84.         As noted above, environmental stakeholders in particular have raised concerns in relation to the protection of the environment under the proposed arrangements, and the impact of streamlining on the environment. While these concerns are understandable, the Taskforce notes that the Strategic Assessment Report, as prepared under Part 10 of the EPBC Act, demonstrates that the proposed arrangements will not have an impact on protection of the environment when compared with business as usual under current arrangements.

1.84.1.    In addition, the benefits of objective-based regulation (paragraph 1.43 refers) will ensure the protection of the environment under the proposed arrangements.

1.84.2.    It is also noted that the Minister for the Environment will decide, in accordance with Part 10 of the EPBC Act, whether to endorse NOPSEMA’s processes.

1.85.         The Taskforce consulted directly with industry in relation to cost estimates and the BCC. The assumptions input to the BCC were developed using data provided by industry and environmental not-for-profit organisations through formal and informal consultation, as well as data from the Department of the Environment and NOPSEMA. The Taskforce then tested the assumptions developed.

1.85.1.    Paragraphs 1.58.1-1.58.2 refer to industry views on these costs. Generally, industry advised that the compliance costs and savings identified were reasonable, noting the variability associated with referral costs.

 


 

Element 6   ̶   Conclusion

1.86.         If the Program is endorsed and classes of actions are approved by the Minister for the Environment, the Government will have delivered on its commitment to streamline environmental approval processes and reduce duplication for offshore petroleum and greenhouse gas storage activities in Commonwealth waters, and in State or Territory waters where powers have been conferred to NOPSEMA.

1.87.         Further, because NOPSEMA’s decision-making processes are based entirely in law.  The regulator cannot make decisions on any basis other than those enshrined in law that has passed both houses of Parliament.

1.88.         This will, as described in paragraphs 1.47 to 1.53:

1.88.1.    Ensure one regulatory point of contact for industry;

1.88.2.    Increase consistency in decision making;

1.88.3.    Ensure only one assessment timeline;

1.88.4.    Remove the risk of conflicting approval requirements;

1.88.5.    Create an overall reduction in the costs to industry, government and the community;

1.88.6.    Increase business certainty and confidence; and

1.88.7.    Raise Australia’s profile as an attractive investment destination.

Element 7   ̶   Implementation and Review

1.89.         Following the consultation period, the Department of Industry and NOPSEMA will submit the Program, a Supplementary Report and the revised Strategic Assessment Report to the Minister for the Environment for consideration for endorsement of the Program by mid February 2014 and approval of classes of actions by 28 February 2014 in accordance with the provisions of Part 10 of the EPBC Act.

1.90.         If approved, the Program will be implemented through changes to the OPPGS(E) regulations (refer paragraph 1.6.1).  Minor amendments will be made as appropriate in response to feedback provided during the stakeholder consultation period.

1.91.         NOPSEMA will provide an annual report on the Program, highlighting the decisions made under the Program, the findings of compliance inspections, environmental incidents reported by titleholders and any investigations underway for the previous year.

1.91.1.    The report will be provided to the Minister for Industry and Minister for the Environment and published on the NOPSEMA website.

1.92.         Under the OPGGS Act, NOPSEMA is subject to operational reviews to assess the effectiveness of NOPSEMA in bringing about improvements in offshore petroleum environmental management, as well as other matters in relation to its functions. The first review is due to take place in 2016, and subsequent reviews will occur every 5 years. The report of the review is to be provided to the Minister for Industry.

1.93.         Under the Strategic Assessment, implementation of the Program will be subject to monitoring, reporting and evaluation. In particular, there will be a review of the Program against the requirements of the EPBC Act after 12 months of operation. The review report is to be submitted to the Minister for Industry and Minister for the Environment. Subsequent reviews will take place every five years.

1.93.1.    The purpose of this and subsequent reviews will be to assess the performance of the Program against Program objectives, including ensuring that impacts on matters protected under Part 3 of the EPBC Act are not unacceptable.

1.93.2.    The first review will include a detailed evaluation of a sample of all decisions made by NOPSEMA to ensure appropriate consideration of matters protected under Part 3 of the EPBC Act.

1.93.3.    The review findings will be provided to the Minister for Industry and the Minister of the Environment within six months of the review’s commencement.


Appendix A: SUMMARY  ̶  Costing Assumptions

1.      Key Assumptions

·         If the Program is endorsed and classes of action approved, the changes to streamline offshore environmental approvals will reduce the overall approval timeframes and increase certainty for proponents.

·         The business costs of offshore development are higher than that of onshore/terrestrial development. As a consequence, the savings associated with streamlined approvals are likely to be higher than for equivalent activities onshore.

·         The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) currently requires all business to complete an Environmental Plan (EP).  This remains unchanged and therefore un-costed. 

·         The Offshore Project Proposal (OPP) is developed earlier and requires detail akin to an Environmental Impact Statement.   The time required to complete an OPP is therefore expected to be less that the EPBC Act approval process.

·         Allowing the submission of an OPP for exploration and other non-development activities to be optional will deliver significant saving to industry while maintaining strong environmental safeguards.

2.      Costing Assumptions

·         All results and inputs are expressed in 2013 dollars.

·         All results are expressed as ‘average annual’.

·         The level of EPBC referral activity (by type of referral) is based on the average annual activity of the past five years (2009 to 2013 inclusive). No adjustments have been made for future growth (i.e. it is assumed that activity over the next ten years will be the same as the average annual activity in the past five years).

3.      Consultation on Assumptions

·         Preliminary estimates calculated were based on data provided by industry, Non-Government Environmental Organisations, the Department of Environment, NOPSEMA and the experience of the member of the Offshore Environmental Streamlining Taskforce, which includes individuals working in the industry and who have a working knowledge of the process and prepared documentation to support referrals and assessments under the EPBC Act and NOPSEMA assessment processes.

·         For industry costings data, the Taskforce requested data from and discussed the proposed costings with:

o   APPEA, as the industry peak body representing 80 oil and gas industry companies and over 250 associate member companies that provide goods and services to the industry.

o   Six companies representing a cross section of small, medium and large operators as well as a cross section across exploration and development activities.

·         The Taskforce asked industry for the following information:

o   A typical example of costings for environmental approvals for petroleum activities in Commonwealth waters.

o   Details of how many exploration and development activities have occurred in the past 5 years.

o   Details of whether industry would seek regulatory approval through the OPP process for exploration activities, given it is not mandatory.

o   The costs of complying with the EPBC Act for a typical development project, and then a typical exploration project, including duration, number and type of staff, consultancies, travel, delay costs, substantive compliance costs and other costs.

·         Industry provided data at different levels of detail and with a focus across different activities. The Taskforce tabulated the data and averaged the input received to protect confidentiality and manage cost differences between entities.

·         The Taskforce then sought feedback on the averaged costs used in the compliance cost calculations with industry stakeholders in a series of discussions as cost assumptions and calculations were revised. The final input data reflects those discussions.

·         Agreed data was also provided by the Departments of Industry and Environment, NOPSEMA, and the environment NGO sector (in particular in relation to not-for-profit costs).

o   Again, the Taskforce sought agreement on the average costings and resulting assumptions in finalising the figures for the compliance cost calculator and broader content in the RIS.

4.      Business Cost Calculator Assumptions

The business cost calculator (BCC) requires that all costs are categorised as either:

·         Notification;

·         Education;

·         Permission;

·         Purchase cost;

 

·         Record keeping;

·         Enforcement;

·         Publication and documentation;

·         Procedural;

·         Other.

 

With the exception of ‘purchase cost’, all of the above are entered as labour costs, and are a function of staff numbers, hours etc. ‘

Purchase cost’ (defined as a product or a service) is a function of the number of times purchased and the cost per purchase.


 

The required inputs are outlined below:


Labour cost (i.e everything except purchase cost)

Purchase cost

Number of businesses affected

Number of businesses affected

Number of staff
per business performing activity

Number of times purchased per year

Number of times activity
performed per year per staff

Cost of service/product per year

Avg. time of each staff
to do activity (in hours)

 

Labour cost ($/hr)

 

 

While the numbers need to be entered into the BCC in the above manner, the RIS is required to report the compliance costs in the below manner:

Average Annual Compliance Costs (from Business as usual)

 

 

 

 

 

Costs ($m)

Business

Community Organisations

Individuals

Total Cost

 

 

 

 

 

Total by Sector

 

 

 

 

 

Cost offset ($m)

Business

Community Organisations

Individuals

Total by Source

Agency

 

 

 

 

Within portfolio

 

 

 

 

Outside portfolio

 

 

 

 

Total by Sector

 

 

 

 

 

Proposal is cost neutral?

 

 

 

 

Proposal is deregulatory

 

 

 

 

Balance of cost offsets

 

 

 

 

 

The RIS costings have been calculated with both of the above requirements in mind. In order to simplify the calculations, all labour costs have been assumed to be ‘permission costs’, or ‘administrative costs’.  All non-labour costs (which primarily include consultancies and flights) are categorised as ‘purchase costs’ and ‘substantive compliance costs’.

The numbers have been entered into the business cost calculator as follows:

·         Exploration

-       EPBC labour costs;

-       EPBC substantive costs.

 

·         Development

-       EPBC labour costs;

-       EPBC substantive costs;

-       OPP labour costs;

-       OPP substantive costs.

The net compliance cost savings are calculated from the above as follows:

Net compliance cost impact =

OPP labour costs + OPP substantive costs – EPBC labour costs – EPBC substantive costs

The exploration EPBC costs provided here do not represent total costs.  They are the costs that would be saved if the EPBC process was removed.  They exclude duplication synergies with the Environmental Plan (EP) process.   This process is to remain unchanged as a result of the regulatory amendments, and it is understood that some of the compliance for an EPBC referral is reused in an EP.  As it is understood that no exploration activities will undergo an OPP under the proposed regulations, the above EPBC costs represent the net savings to exploration activities.

The development EPBC costs do represent total costs.  The OPP labour costs are the same as EPBC labour costs, with a lower average time for each staff to do a required activity.  Information provided to the Taskforce by NOPSEMA[25], industry participants (including APPEA)[26] and eNGOs[27] suggests that the time saving is approximately 45 per cent. 

Under the OPP substantive costs, consultancies costs are assumed to be the same under the OPP process as the EPBC process.  Flights to Canberra are assumed to be a saving, while an additional cost included here is the cost recovery fee payable by industry to NOPSEMA to assess OPP applications.


5.      Detailed BCC explanations

Data input to the BCC

 

 

Exploration

Development

ACTIVITY

EPBC Labour Costs

EPBC Substantive

EPBC Labour Costs

EPBC Substantive

OPP Labour Costs

OPP Substantive

COST CATEGORY

Purchase costs

Permission

Purchase costs

Permission

Purchase costs

Permission

COST TYPE

Labour (internal)

Service (outsourced)

Labour (internal)

Service (outsourced)

Labour (internal)

Service (outsourced)

No. OF BUSINESSES AFFECTED

48

48

13

13

13

13

NO. OF TIMES SERVICE PURCHASED PER YEAR:

 

1.78

 

0.18

 

0.18

SERVICE COST PER ACTIVITY ($):

 

$14,359.15

 

$212,967.00

 

$199,167.00

No OF STAFF PER BUSINESS PERFORMING THE ACTIVITY

1

 

1

 

1

 

NO. OF TIMES EACH STAFF DO ACTIVITY (HOURS):

1.78

 

0.18

 

0.18

 

AVG. TIME OF EACH STAFF TO DO ACTIVITY (HOURS):

281.75

 

3878.7

 

2137.5

 

LABOUR COSTS ($/HOUR)

$297.00

 

$297.00

 

$297.00

 

 


Number of businesses affected by the activity

-        These numbers were drawn directly from the Department of Environment’s EPBC Proposals - offshore oil and gas, seismic database. Because the OPP is required for all development businesses but is voluntary for exploration activities the OPP figures assume the number of businesses affected by the activity is equal to the number of development businesses.

Number of staff per business performing activity

-        For the purposes of the BCC calculation this figure was assumed to be one (a representative aggregate person that captures all of the staffing categories).

Number of times activity performed per year per staff

-        Deriving this figure involved a number of steps. 

-        The total number of development and exploration activities referred under the EPBC Act was drawn directly from the Department of Environment’s EPBC Proposals - offshore oil and gas, seismic database. 

-        Using this data, industry intelligence and advice from NOPSEMA on the number of EP applications received since its inception in 2012, it was assumed that approximately 20 per cent of all exploration activities are referred under the EPBC Act.  From this the total the number of exploration activities could be determined. 

-        In determining the number of times an activity was performed it was recognised that although only 20 per cent of exploration activities are not referred there is still some compliance burden for the other 80 per cent who will undergo some work to determine whether a referral is required in their case.

-        The OPP figure was calculated using the same assumptions as for a EPBC development activity.

Avg. time of each staff to do activity (in hours)

-        Deriving this figure also involved a number of steps.  The total number of internal staff (working hours) was calculated using detailed costing data provided by industry. 

-        Firstly the sum of the total number of internal staff (working hours) across all EPBC referral activities was divided by the sum of the length of phase (working days) across all EPBC referral activities, adjusted to give you the total number of internal staff per phase.

-        The adjustment factor recognises that a proportion of the work required to prepare an EPBC Act referral for an exploration project can be reused in the NOPSEMA EP process.

-        The length of phase differs between development and exploration referrals and also between the application process and assessment phase for both controlled and non‑controlled actions.  Using figures provided by industry and assuming there are 250 working days per year, the BCC calculation assumes:

For a Development Activity:

o   The application process takes 125 days (6 months of a working year) to complete

o   The assessment phase takes 62.5 days (3 months of a working year) to complete

For an Exploration Activity:

o   The application process takes 83.3 days (4 months of a working year) to complete,

o   The assessment phase is assumed to be same as for a development activity.

-        The average time of each staff to do the activity (in hours) is then the sum of the total number of internal staff (working hours) per phase required for the EPBC application process and assessment phase, for both controlled and not controlled actions, minus the total number of internal staff (working hours) required for the NOPSEMA EP process.

For an OPP:

-        Using estimates provided by NOPSEMA, the BCC assumes there is labour saving of approximately 45 per cent when preparing an OPP when compared to a development activity.

o   The application process is assumed to be the same as for a development activity adjusted by a factor of 54 per cent.

o   The assessment phase is assumed to be same as for a development activity adjusted by a factor of 54 per cent.

-        This is derived by assuming it would take 7.5 months to develop an OPP (the mid-point in time between 6‑9 months for a business to develop a simple EPBC referral (no public report or EIS statement) and dividing this by the average estimated time it takes a business to prepare a simple development referral under the current EPBC process (derived using data from the Department of Environment’s EPBC Proposals - offshore oil and gas, seismic database).

-        Based on advice from industry, the BCC assumes that businesses will not prepare an OPP for exploration activities under the new regime.

Average labour cost ($/hr) (wage + non-wage)

The BCC has used the detail data provided by industry to determine the average labour cost ($/hr) (wage + non‑wage) associated with submitting an EPBC Act referral.  The costing encompasses both the application and the assessment phases.  It is calculated by taking the number of staff (measured as total staff working days) the business has allocated to each phase and multiplying this by their staff costs per day (including on-costs).  These costs are then summed across staffing categories (i.e. administration, management, environmental scientists, lawyers, engineers etc.).  The average of the total cost was then calculated to give the internal staff average cost per working day.  This was then divided by eight (a standard working day) to derive the $/hr figure. The hourly labour figure for all business was then averaged to derive the average labour cost ($/hr) (wage + non‑wage) of $297 used in the BCC for all activities.

The Taskforce received detailed staff costings from a number of ‘mid-sized’ petroleum businesses engaged in both exploration and development activities.  Several other businesses covering smaller scale operations through to industry leaders also provided costings and guidance on the scope of the effort required when referring an activity.  It is typically the case that smaller operators who do not have significant in-house resources tend to face higher costs for a referral, while those dominant in the sector have achieved a degree of scale and internal efficiency that means they are able to respond to the demands of the referral requirements more cost effectively. 

Industry advice suggests this is an underestimation of the true cost.  At least one proponent strongly argues the figures were far too low.  Larger firms agreed the numbers were perhaps under representative, but agreed them to be a reasonable ‘ball-park’ figure.

Number of times service purchased per year

-        This is assumed to be equal to the number of businesses affected divided by the average annual number of EPBC referrals in the past five years for all activities (data drawn from the Department of Environment’s EPBC Proposals - offshore oil and gas, seismic database).

Service cost per activity ($)

-        The service cost per activity has been calculated using detailed costings data provided by industry participants.

-        Consistent with the BCC Handbook, July 2013, the cost recovery fee payable by industry to NOPSEMA to assess applications is not costed.

For the OPP

-        Consultancies costs are assumed to be the same as for a development activity EPBC referral.

-        The BCC figures assume that flights to Canberra normally associated with the EPBC referral application process and assessment phase will not be required for an OPP.

 


Detailed BCC Calculated Results

Exploration

Exploration EPBC Labour Costs

 $ 7,149,597.84

Exploration EPBC Substantive Cost:

 $ 1,226,845.78

Total Exploration Activity Compliance Costs

 $ 8,376,443.62

Development

Development EPBC Labour Costs

 $ 2,695,618.93

Development OPP Labour Costs

 $ 1,485,519.75

Development EPBC Substantive Cost

 $ 498,342.78

Development OPP Substantive Cost

 $ 466,050.78

Total Development Activity Compliance Costs

 $ 5,145,532.24

Development OPP Labour Costs + Development OPP Substantive Cost (A)

 $ 1,951,570.53

Total Exploration Activity Compliance Costs + Development EPBC Labour Costs + Development EPBC Substantive Cost (B)

-$ 11,570,405.32

A + B

-$ 9,618,834.79

Not-for-Profit

-$ 668,275.82

 

Explanation for Adjustment to BCC Result to Account for OPP Activity Costs

$ 13,521,975.85

BCC generated total compliance costs savings.  Includes OPP activity costs.

$ 11,570,405.32

Removes sum of OPP activity cost from BCC calculation to derive actual BCC total compliance cost figure.

$ 9,618,834.79

Removes new regulatory impost incurred by introduction of OPP process from total business compliance costs saving

$ 10,287,110.61

Recognises estimated not-for-profit sector compliance cost savings

 


Appendix B: Summary of issues/ comments raised during public consultation and Taskforce response

 

Issues and discussion

Action

1.1          Environmental protection under the Program

 

1

Protection of matters protected under Part 3 of the EPBC Act[28]

A number of submissions commented on the protection of matters under Part 3 of the EPBC Act under the Program. Submissions from industry supported the Program and its ability to deliver environmental outcomes equivalent to those achieved under the EPBC Act while environmental NGOs raised concerns.

Concerns raised related to:

·         perceived lack of explicit and specific commitment in the Program to EPBC Act objects, statutory documents and relevant international agreements;

·         level of legal protection afforded by the Program (through the Regulations);

·         ability of the program to achieve protection without specific and detailed prescriptions;

·         explicit and vigilant application of the precautionary principle; and

·         delegation of approval powers away from the Minister for the Environment in relation to Protected Matters.

Several other submissions identified other legislation and treaties relevant to protection of the marine environment and queried whether these were integrated into the Program.

Response

The Taskforce considers that the Strategic Assessment Report, prepared in accordance with the Terms of Reference, demonstrates how the Program provides for environmental outcomes equivalent to those achieved under the EPBC Act.

The Taskforce notes that the Program addresses protection of Part 3 Protected Matters in some detail (refer to Section 1.7, Section 8, Part C and Appendix A); it makes commitments and describes how they will be protected, including through reference to statutory obligations and documents, such as plans of management, listing statements and recovery plans. The Strategic Assessment Report (Chapters 4, 5 and 7, in particular) also describes in some detail how matters under Part 3 of the EPBC Act will be protected under the Program. The Taskforce also points out that to the Strategic Assessment Report, which specifically addresses the how the Program addresses the objects of the EPBC Act, principles of ESD and the precautionary principle (in Chapter 4).

While the Taskforce considers these matters have been sufficiently addressed, it suggests that some concerns may arise from lack of familiarity among some environmental NGOs with the objective-based approach to regulation under the Program as opposed to the prescriptive approach under the EPBC Act. On the other hand industry stakeholders are familiar with and have confidence in the objective based approach. The objective-based approach to regulation under Program is discussed both in the Program Report (Section 3) and Strategic Assessment Report (Chapters 3 and 8). Objective-based regulation requires titleholders to achieve particular environmental outcomes, but does not prescribe the specific method or means to do so. It places the duty on the titleholders to meet and demonstrate they have met these outcomes. Chapter 7 of the Strategic Assessment Report describes scenarios (case studies) to illustrate how objective-based regulation under the Program ensures environmental protection.

The Taskforce is of the view that the objectives-based approach is in fact a key strength of the Program, and has the potential to improve environmental outcomes, including protection of Part 3 matters. Objective-based regulation allows flexibility to ensure adaptive management, innovation in methodology and continuous improvement in achieving acceptable environmental outcomes. It also ensures the relevance, currency and ongoing appropriateness of regulatory controls.

The Taskforce, however, acknowledges the concerns raised, and has added further detail about the protection of matters under Part 3 of the EPBC Act to the Program and Strategic Assessment Report, to ensure all stakeholders are satisfied.

Other matters

With respect to the other issues raised, the Taskforce emphasises that NOPSEMA has no formal legislative responsibility for other international treaties and/or legislation relating to the environment. Consequently the Program itself does not refer to these, although the Strategic Assessment Report (section 5.6) notes them as part of the broader context of the Program. The Taskforce also points out that the content requirements of Environment Plans and Offshore Project Proposals under the Program mean that any permits and/or responsibilities and commitments required by the titleholder be described, and any actions identified. The Taskforce suggests that NOPSEMA will continue to liaise with other agencies with regard to these matters, but is of the view that no change is required to the Program or Strategic Assessment Report.

Submissions that referred to this issue: 3, 6, 7, 10, 14, 15, 18, 19, 21, 28, 35, 38.

 

The Taskforce has:

·         added information to Part B(Section 8), Part C and Appendix A of the Program Report in relation to protection of matters under Part 3 of the EPBC Act

 

·         added information to Chapter 7 of the Strategic Assessment Report in relation to protection of matters under Part 3 of the EPBC Act.

2

NOPSEMA capabilities to assess impacts on Protected Matters

A number of submissions questioned if NOPSEMA has the necessary level of corporate and technical experience required for environmental assessments under the EPBC Act, noting NOPSEMA was only established as an independent statutory authority under the OPGGS Act on 1 January 2012. Some submissions queried how NOPSEMA would raise adequate funds to remain effectively resourced going forward.

Submissions also specifically queried NOPSEMA’s capability to assess potential impacts on matters of national environmental significance (MNES), particularly acoustic impacts on cetaceans and the maintenance of access to environmental expertise through DoE.

Response

As noted in Issue 27 (Cost Recovery), NOPSEMA operates on a full cost recovery basis, which ensures it has the resources to maintain appropriate and specialist environmental expertise. NOPSEMA also has the ability to seek external expertise on a case-by-case basis. The Program provides that NOPSEMA will enter into administrative arrangements with the Department of the Environment to ensure appropriate information sharing for implementation of the Program. The Taskforce notes that as of January 2014 NOPSEMA and the Department of the Environment have already commenced work in relation to implementation activities.

Submissions that referred to this issue: 3, 21, 22.

The Taskforce has clarified specific sections (4.4, 5.2, 9.3) of the Strategic Assessment Report as set out in Issue 27 (Cost Recovery).

1.2          Cumulative impacts

 

 

3

Cumulative impacts should be explicitly and transparently considered in the Program

Submissions noted a number of issues regarding the consideration of cumulative impacts during Offshore Project Proposal and Environment Plan development:

Due consideration

Concerns were raised that cumulative impacts may not be adequately considered as there is no specific regulatory requirement to do so. The Environmental Defender’s Office of Western Australia stated that “Under the Program, an OPP can be obtained prior to all information relevant to the particular project being obtained but there may be no way at that stage to accurately assess what the cumulative effects of the project might be until further work is done.”

It was also suggested that Offshore Project Proposals may not consider the full range of associated activities and therefore not consider the full range of risks and impacts. Submissions recommended that the regulations should make it explicit that cumulative impact assessment must be undertaken and that assessments should consider impacts over the life of the activity and over a region, for example in relation to multiple simultaneous discharges. It was also recommended that NOPSEMA should have the power to assess cumulative impacts, request that cumulative impacts are assessed if not present in the submission, and publicly report on cumulative impacts. One submission also recommended that social and economic impacts be included as a part of cumulative impact assessment.

Review

Submissions also recommended ongoing review, consideration and reporting of cumulative impacts. One submission suggested that ongoing reassessment of cumulative impacts should be considered for Offshore Project Proposals and Environment Plans, and setting and monitoring environmental outcomes can address this. “A regular review of cumulative impacts under the Offshore Project Proposal and the power to issue directions about future Environment Plans’ impact on particular concerns may address this,” was suggested by the Environmental Defender’s Office of Western Australia.

Guidance

Submissions indicated there is a need for guidance around cumulative assessment with specific consideration afforded to the measurement of cumulative impacts, consideration of impacts over time (i.e. for the life of the activity), seasonal timing, consecutive and simultaneous activities, and all associated activities including marine traffic and monitoring. In addition, there were strong statements around the need to consider how cumulative impacts will be assessed and measured in an agreed manner before inclusion in Regulation as without this clarity the effectiveness of streamlining may be affected.

Data

Submissions noted existing limitations on access to adequate data for cumulative impact assessment. Data sharing issues were also limiting availability of data for cumulative impact assessment purposes.

The key point raised was that due to commercial and technical constraints, individual titleholders cannot reasonably be expected to have detailed knowledge of the environmental status and activities that are occurring in neighbouring leases, and therefore are essentially unable to effectively determine the cumulative impacts of the proposed activity nor to comprehensively describe the receiving environment.

It was recommended that the development of information on data standards, data coordination, centralised data management and the release/sharing of non-commercially sensitive data is necessary. There were also concerns raised that titleholders will not have access to sufficient information to consider cumulative impacts because the data is not available.

Response

The Taskforce notes the concerns in relation to consideration of cumulative impacts under the Program. Additional information on cumulative impacts has been included in the Strategic Assessment Report. More broadly, the Taskforce recognises the consideration of cumulative impacts in environmental impact assessments is a challenge nationally and internationally for regulators, policy makers and proponents.

The Program specifically refers to the matter of cumulative impact assessment in Sections 4.5.1 and 5.1.1 of the Program Report. The Program presents a positive step forward for effective consideration of potential cumulative impacts associated with offshore petroleum and greenhouse gas activities. The objective-based regime requires proponents to demonstrate continuous improvement. This ensures that ongoing impacts must continue to be identified and reduced to ALARP (as low as reasonably practicable) via appropriate monitoring activities. ALARP requires that control measures continue to be effective in ensuring that impacts and risks will remain within acceptable levels and those environmental performance outcomes will continually be met. This objective-based framework means that the Regulations do not need to have a specific reference to cumulative impacts.

A benefit of the Program is that NOPSEMA, as the single national regulator, will assess Offshore Project Proposals earlier in their development stream. This will ensure appropriate consideration of lifecycle and cumulative impacts through the implementation of the Offshore Project Proposal process.

The Taskforce acknowledges that there are limitations in the data currently available across the offshore petroleum sector, and agrees that data is important to facilitate detailed cumulative impact assessments. The Taskforce encourages industry to pursue data sharing opportunities to ensure access to relevant information. Data is discussed further in the Environmental Data section below (Issue 4).

Submissions that referred to this issue: 3, 6, 7, 11, 12, 22, 28, 37

The Taskforce has added information on how the Program takes into account cumulative impacts to Section 4.3 and Appendix 4 of the Strategic Assessment Report.

1.3          Environmental data

 

 

4

Baseline environmental data

A number of submissions, as well as comments from industry stakeholders during information sessions, noted the lack of a central repository for environmental and other data that could be of use in determining a baseline for environmental conditions and to inform ongoing monitoring of the environment over time. It was noted that adequate information and data helps to ensure the appropriate assessment and management of potential impacts and risks on the environment, particularly in the long term and in relation to considering cumulative impacts (refer to Issue 3).

Further, submissions suggested that, under the Program, the Government would lose its ability to compel a proponent to provide and make certain environmental data associated with a proposal public.

Response

The Taskforce recognises the importance of baseline data and supports collection and publication of data to improve understanding of the marine environment for all stakeholders. It is important to note, however, that the EPBC Act does not currently require proponents to publish data.

The Taskforce acknowledges the benefit that would be achieved through improvement in collection, availability and access to data by stakeholders. Sharing of data would reduce the cost to industry of baseline information acquisition and enable a more sophisticated data set for the assessment of environmental impacts and risks. The Taskforce recommends that the Department of Industry pursue this as a policy issue through the Energy White Paper process. \

Submissions that referred to this issue: 12, 14, 21, 22, 38.

 

The Taskforce has recommended that the Department of Industry pursue this matter via the Energy White Paper.

1.4          Decision-making processes

 

5

Definitions and parameters for decision-making

Some submissions suggested changes to the way the Program references and defines environment, matters of national environmental significance (MNES), and the principles of Ecologically Sustainable Development (ESD).

These submissions proposed that the principles of ESD, including the precautionary principle, should form part of the acceptance criteria for both Offshore Project Proposals and Environment Plans (through reference in the definition of ALARP), to improve clarity and help ensure strong environmental safeguards are maintained.

Submissions also suggested that:

·         certain terms should be defined in Regulations to provide additional clarity in decision-making, including: ‘reasonably satisfied’, ‘appropriate’, ‘significant impact’, ‘acceptable’ and ‘unacceptable’

·         for the definition of ‘environment’ to be amended to refer specifically to MNES, and that this change would ensure threatened and migratory species in particular are adequately protected under the endorsed Program

·         clarification on how social and economic factors, as referenced in the definition of ‘environment’, are taken into account in decision-making processes be provided

·         references in the Program be changed from ‘critical habitat’ (as defined and given legal meaning under the EPBC Act – s207A) to threatened and migratory species to ‘biologically important habitat’, due to the fact that many more species have such habitats identified in marine bioregional plans.

Response

The definition of the ‘environment’ in the Program mirrors the EPBC Act. Many other terms used in the Program such as ALARP, reasonably satisfied, and acceptable have legally accepted meanings with a basis in case law. These deliberately have not been defined to avoid the risk of unintentionally narrowing their definition or creating the circumstances for unintended legal consequences. The Taskforce has, however, included an explicit reference to Part 3 matters of the EPBC Act as part of the description of the environment required for an Offshore Project Proposal and Environment Plan. 

The principles of ESD are defined in the OPGGS(E) Regulations. The Program’s acceptance criteria (Section 5.1) requires that an Environment Plan must comply with all requirements of the OPGGS Act and OPGGS(E) Regulations; therefore, if an Environment Plan meets the acceptance criteria, it must meet the principles of ESD as required in the Regulations. ESD principles are also a consideration of an Offshore Project Proposal, where the key consideration is about the acceptability of the whole of the project including the appropriateness of the ‘nature and scale’ of the project, environmental evaluation and performance outcomes, and public consultation.

The Program provides for the development of guidance material by NOPSEMA to provide further clarity, where required, on terms relied on in the Program that are demonstrated to need further definition. Such guidance will operate similarly to current EPBC Act guidelines (e.g. on significance). The Program has mandated reviews, which provide for analysis of the effectiveness of the Program’s operation. These reviews will also identify areas where guidance should be developed.

The Taskforce does not consider it necessary to change ‘critical habitat’ to ‘biologically important habitat’ as the Program uses the language of the EPBC Act and its supporting policy guidance documents.

On balance, the Taskforce considers that the case for amendments to references and definitions in the Program has not been made. The Taskforce has, however, amended the OPGGS(E) Regulations to included specific reference to Part 3 Protected Matters in the description of the environment requirements for both the Offshore Project Proposal and Environment Plan processes.

Submissions that referred to this issue: 1, 3, 5, 7, 8, 21, 22, 27, 29, 31.

The Taskforce has included an explicit reference to Part 3 matters of the EPBC Act as part of the description of the environment required for an Offshore Project Proposal and Environment Plan in the OPGGS(E) Regulations.

6

Assessment and decision-making through public inquiry

Three submissions noted the capacity under the EPBC Act for the Minister for the Environment to decide that assessment of a controlled action should be by public inquiry. Several submissions suggested that this approach could be a form of review. It was also suggested that the ability to call a public inquiry of this nature should be retained or provided to NOPSEMA under the Program.

Response

A public inquiry assessment approach under the EPBC Act is where the Minister for the Environment assigns a commissioner to investigate a matter. The commissioner determines the assessment process they will use – which may be the equivalent of an environmental impact statement (EIS) – and usually invites submissions from the public. This method of assessment has seldom been used under the EPBC Act. EPBC Act guidance material states a public inquiry is “appropriate where impacts are likely to be outside the control of a single proponent” and it is necessary or desirable to have a commissioner oversee the assessment process.

A public inquiry assessment approach is not considered necessary as NOPSEMA regulates the actions and environmental consequences of individual titleholder’s activities. Furthermore, the Program establishes an Offshore Project Proposal process that provides for a detailed early assessment of an individual proponents project. An Offshore Project Proposal mandates public consultation and is early notification of a project. The Offshore Project Proposal is roughly equivalent to an EIS under the EPBC Act.

On this basis the Taskforce has not included the suggestion for assessment, decision-making and/or review to be conducted through public inquiry.

Submissions that referred to this issue: 10, 19, 21.

The Taskforce has not taken any further action on this issue.

7

Independence of NOPSEMA as decision-maker

Industry stakeholders generally supported the transfer of decision-making power to NOPSEMA for matters protected under Part 3 of the EPBC Act. Environmental stakeholders indicated a preference that the decision remains with the Minister for the Environment. One submission also suggested that the final decision remain with the Minister for the Environment while assessment functions could be transferred to NOPSEMA.

Some submissions expressed concern that the proposed regulatory framework may result in unintended consequences, noting NOPSEMA is not privy to broader national interest knowledge held at the Ministerial level and that it does not have a mandate to make decisions that balance environmental as well as economic and social considerations.

One submission suggested that there was not a separation of powers as NOPSEMA was both assessor and decision–maker and that this posed a risk for decision-making, while another recommended that environmental assessment processes need to be independent of government departments.

 

Response

Several government inquiries have noted duplication of environmental assessments for the offshore oil and gas industry. The Program removes this duplication by setting out environmental standards and commitments equivalent to the EPBC Act that NOPSEMA must meet in undertaking its assessment processes.

In response to concerns over the independence of the decision-maker, the Taskforce notes that NOPSEMA is an independent statutory authority. NOPSEMA has been established under the OPGGS Act with the clear purpose of separating the policy and resource promotion aspects of the offshore petroleum industry from the environmental, safety and well integrity regulation of that industry. This model is consistent with international regulatory practice for high-hazard industries.

The Department of the Environment will remain responsible, under the EPBC Act, for policy matters such as species listings, recovery plans, conservation and policy advices (all required to be considered by the Program). If the Program is endorsed and approved under the EPBC Act monitoring and compliance of the Program will remain the responsibility of the Department of the Environment.

The Taskforce has not amended the Program or Strategic Assessment Report in response to submissions on the independence of NOPSEMA as a decision-maker.

Submissions that referred to this issue: 10, 13, 17, 22, 33.

The Taskforce has not taken any further action on this issue.

8

Processes and information required for decision-making

A significant number of submissions sought clarity on the implications of the requirement to consider documents that are prescriptive in nature (such as EPBC Recovery Plans and Management Plans) and not developed by NOPSEMA. It was noted that these requirements may lead to industry confusion, duplication and ad-hoc and subjective regulation.

Submissions from environment stakeholders suggested that Environment Plans should include more information. In particular, they suggested that the Program should specifically require Environment Plans to include information on the environmental track record of the titleholder; whether the impacts of the activity are likely to be unknown, unpredictable or irreversible; and the source, date and reliability of all information.

Submissions also noted that:

·         Environment Plans, like Offshore Project Proposals, should discuss alternative options for conducting activities

·         NOPSEMA should only approve Environment Plans for 12 months at a time, and should not approve ‘strategic’, or diverse, multi-year Environment Plans

·         EPBC Act Policy Statement 2.1 is outdated and should be revised

·         NOPSEMA did not have sufficient expertise in marine ecology and that a Memorandum of Understanding would be required between NOPSEMA and the Department of the Environment to provide access to their expertise.

 Response

The Department of the Environment will remain responsible for developing plans and guidance in accordance with its responsibilities under the EPBC Act and the Australian Government’s international treaty obligations. Section 10.3.2 of the Program refers to EPBC Act plans, policies and guidance that are relevant to the offshore oil and gas industry. The Program states that NOPSEMA will develop guidance material and undertake assessments with regard to these relevant policy documents. Appendix A of the Program commits NOPSEMA to consider particular plans or advices, such as plans of management and recovery plans, which are a statutory requirement of the EPBC Act.

The assessment processes outlined in the Program draw on NOPSEMA’s current assessment and decision-making framework which is a merit based assessment system that challenges and analyses the titleholder’s case presented in their Environment Plan. NOPSEMA, as a regulator, is dedicated specifically to the offshore oil and gas industry. The purpose of NOPSEMA’s establishment was to develop an agency that has good knowledge of the industry and the ability to meet environmental and safety commitments. As the dedicated petroleum regulator, NOPSEMA is aware of a proponent’s track record in achieving environmental objectives and their ongoing compliance. NOPSEMA adapts compliance and enforcement activities based on risk and a range of other matters, including a proponent’s environmental record. Information on this is available on NOPSEMA’s website.

The Program describes the Environment Plan and Offshore Project Proposal processes. These are different assessment paths based on activity type. As described in the Strategic Assessment Report, the Offshore Project Proposal assessment captures development activities. As such, the Offshore Project Proposal provides for an early publication, notification, and assessment process. Public notification enables stakeholders to provide information on a range of matters, including alternatives to the proposal and a proponent’s environmental record. In an Offshore Project Proposal a proponent is able to consider alternatives because its submission is at an early stage in the project’s development. The requirement for consideration of alternatives is a fundamental principle of environmental impact assessment and is already applied. This requirement is consistent with current EPBC assessment processes. The Environment Plan process in this regard remains unchanged. The Taskforce notes that such a change would increase duplication as an Environment Plan is required as a later step (following an Offshore Project Proposal). It is considered that duplicating the requirements of an Offshore Project Proposal at the Environment Plan stage does not provide material benefit. The Taskforce notes several submissions raised the issue of ‘consultation fatigue’ and additional requirements have potential to add to this issue.

The Environment Plan process provides for stakeholder engagement of ‘relevant persons’. These persons may make submissions on relevant matters such as feasible alternatives or a proponent’s environmental record. The Program provides for receipt of Environment Plans to be notified on the NOPSEMA website.

Refer to Issue 24 for detail on NOPSEMA’s expertise and personnel.

The Taskforce considers that there is merit in further clarifying current arrangements in the Strategic Assessment Report. However, the Taskforce has not adopted the suggestions put forward in submissions.

Submissions that referred to this issue: 4, 7, 15, 19, 21, 22, 27, 28, 36.

The Taskforce has updated Section 5.2 of the Strategic Assessment Report to clarify current arrangements and how they apply to the Program.

 

1.5          Offshore Project Proposal Process

9

Requirements for an Offshore Project Proposal

A large number of submissions sought clarification on a proponent’s obligations to submit an Offshore Project Proposal, including for exploration activities, new activities, and decommissioning activities.

Several submissions, in particular from environmental stakeholders, recommended that an Offshore Project Proposal should be required for exploration activities as well as development activities, while others suggested the requirement for an Offshore Project Proposal should be based on the significance of potential impacts.

Submissions also suggested further clarity was required regarding the ability for proponents to submit an Offshore Project Proposal for exploration activities. Some stakeholders recommended that NOPSEMA have the right to require an Offshore Project Proposal for exploration activities on a case-by-case basis, or that NOPSEMA and the proponent should at least consult on the question for exploration activities.

Submissions sought clarity on whether a decommissioning activity would require an Offshore Project Proposal, noting the Offshore Project Proposal content requirements refer to decommissioning activities, but those activities are not part of the draft definition of an ‘offshore project’. Submissions also sought clarification on the definition of ‘offshore project’, highlighting inconsistencies between the amendment Regulations, Program and draft Strategic Assessment Report. It was suggested that ‘development’ could also be defined. Clarification was sought regarding greenhouse gas activities under the Program and one submission supported their inclusion.

Response

Separate Offshore Project Proposal and Environmental Plan assessment streams are fundamental to the streamlining process.

The Offshore Project Proposal must describe the whole lifecycle (including activities that will be likely to take place such as development drilling, construction, operation and decommissioning) of the proposed project and include a mandatory period of public consultation. Subsequent Environment Plans will be required for all activities encompassed in the project.

Proponents may also elect to submit an Offshore Project Proposal for an activity that is not part of a development project, to take advantage of the key steps, including public consultation. The Program states that NOPSEMA will provide guidance about matters proponents may wish to consider in deciding whether to submit an Offshore Project Proposal for exploration activity.

An Offshore Project Proposal submission can be scaled to be appropriate to the nature of the proposed development and the receiving environment in which it is to take place while still meeting all the content requirements prescribed by the OPGGS(E) Regulations. The Program states that NOPSEMA will prepare guidance on meeting the regulatory requirements for Offshore Project Proposals.

Requiring an Offshore Project Proposal for all activities, such as seismic surveys, will increase regulatory burden and is not considered necessary to ensure high environmental standards are maintained. Prior to the Strategic Assessment, under the EPBC Act, proponents made a decision whether to refer actions based on their own assessment of significance; the result was that not all offshore oil and gas projects were referred. Requiring an Offshore Project Proposal for all such projects would therefore increase the regulatory burden and not in any way improve environmental outcomes.

The Taskforce has clarified the definition of an ‘offshore project’ in the amendments to the Environment Regulations.

Submissions that referred to this issue: 4, 5, 7, 9, 12, 15, 18, 19, 22, 25, 27, 30, 31, 36,38.

The Taskforce has clarified the definition of an ‘offshore project’ in the amendments to the OPGGS(E) Regulations.

10

OPP process and streamlining: changes to, or additional activities

Some submissions expressed concern that the Offshore Project Proposal process may, in certain scenarios, increase regulatory burden, to the detriment of streamlining.

Submissions sought clarity on Offshore Project Proposal requirements for new activities planned in relation to an existing Offshore Project Proposal approval. They generally recommended that such new activities should not require a new Offshore Project Proposal, or should only do so if the new activities were extensions to existing projects where the environmental risk or impact may be unacceptable.

Submissions noted the potential for activities that would not have been referred under the EPBC Act to require an Offshore Project Proposal under the Program, particularly in the case of minor offshore drilling campaigns and additional drilling (tie-backs) as part of an existing project. It was also suggested that the content requirements for an Offshore Project Proposal could be more onerous than current EPBC Act requirements, in particular for smaller projects.

Submissions highlighted that the Program does not provide for revision or amendment of an Offshore Project Proposal, and sought clarification on whether changes in an activity requiring an Offshore Project Proposal would mean a new or additional Offshore Project Proposal was required. It was suggested that this would be more onerous than current EPBC processes.

Response

The distinction between an Offshore Project Proposal and an Environment Plan in the Program ensures those activities with the potential for higher environmental impacts undergo early public consultation through the Offshore Project Proposal process. All activities, including those with lower potential environmental impacts will undergo an Environment Plan assessment. The Offshore Project Proposal and Environment Plan pathways have an activity basis that is linked to the types of activities authorised by title under the OPGGS Act. The purpose of this is to remove ambiguity. Under the EPBC Act, proponents are required to make a decision whether to refer actions based on their own assessment of significance. This can result in uncertainty for industry about when to refer, and over regulation because proponents submitted ‘precautionary’ referrals. Having an activity based trigger removes the ambiguity about which process applies and increases overall efficiency by reducing ‘double-handling’.

The Taskforce notes the concerns raised in submissions relating to new development activities planned, but which are connected to existing projects. The Taskforce acknowledges that some minor development activities may have been required to have an Offshore Project Proposal under the draft Program that may not have otherwise been referred under the EPBC Act.

The Taskforce has considered this issue at length, discussing it and potential solutions with a number of industry participants throughout the consultation period. As a result of these discussions, the scope of activities that will be mandatory for an Offshore Project Proposal has been amended. An Offshore Project Proposal will be required for all new development activities that do not have prior EPBC Act Part 9 approval. Additional or new stages of existing developments will not be subject to the mandatory Offshore Project Proposal provisions, but will of course, require an accepted Environment Plan in place before any new stage of an activity can commence.

The Taskforce considers that an Offshore Project Proposal revision mechanism is not required. NOPSEMA’s compliance mechanism is through Environment Plans. A final Environment Plan may be revised from the original Offshore Project Proposal that was submitted for the activity; in this case, if there is a difference between an initial Offshore Project Proposal and Environment Plan, the Environment Plan must explain these differences, and demonstrate how performance outcomes are appropriate (with reference to modifications from the original Offshore Project Proposal).

The Taskforce recognises there may be some transitional uncertainty about the Offshore Project Proposal process for proponents. Further clarification has been provided in the Strategic Assessment Report and NOPSEMA will include further information on this matter in its guidance.

Submissions that referred to this issue: 9, 11, 15, 24, 27, 29, 30, 33, 34.

The Taskforce has:

·         amended the requirement for an Offshore Project Proposal to apply to only new development activities in the OPGGS(E) Regulations.

·         provided further clarification in Section 5.2 of the Strategic Assessment Report.

 

The Taskforce also notes that NOPSEMA is preparing guidance for proponents about Offshore Project Proposal assessment process. This will specify information requirements for an Offshore Project Proposal appropriate to nature and scale of the activity.

11

Offshore Project Proposal process and streamlining: Offshore Project Proposal and Environment Plan processes

Submissions questioned whether having both an Offshore Project Proposal process and an Environment Plan process requirements would increase the level of assessment and regulatory burden compared with current arrangements.

Submissions also sought clarification on the possibility of parallel assessment of Offshore Project Proposals and Environment Plans, noting that the amendment Regulations as drafted would not allow for parallel processing as an Environment Plan must not be submitted unless an Offshore Project Proposal has been accepted.

Response

Streamlining under the Program offers benefits of a single independent regulator, and a legal framework under the Program which is objective-based. While parallel assessment of an Offshore Project Proposal and Environment Plan is not possible, proponents are encouraged to think strategically about how to approach the Offshore Project Proposal to maximise flexibility under the model and how the preparation of an Offshore Project Proposal can contribute to and streamline the development and assessment of subsequent and related Environment Plans.

 As described in item 10 above, the Taskforce considers the certainty provided by having a clear activity based definition about when an Offshore Project Proposal applies, combined with NOPSEMA guidelines about information requirements for an Offshore Project Proposal delivers a net regulatory reduction benefit.

Submissions that referred to this issue: 9, 11, 15, 24, 27, 29, 30, 33, 34.

The Taskforce has taken no further action on this matter.

12

Detailed Offshore Project Proposal processes and guidance

Submissions sought clarification on certain process matters for Offshore Project Proposals, and made recommendations for NOPSEMA guidance development and content.

Submissions sought clarification on the level of detail required in an Offshore Project Proposal, including whether performance outcomes and management controls would need to be identified.

Submissions also questioned whether the provision allowing NOPSEMA to request additional information on an Offshore Project Proposal inferred that proponents would only have one opportunity to provide further information before a complete resubmission would be required. It was recommended that, if this is the case, clarification was needed on whether public consultation would be required for a second Offshore Project Proposal submission.

Submissions recommended Offshore Project Proposal guidance, including guidance on framing environmental performance outcomes, should be made available by the date of commencement of the Regulations. It was also recommended that NOPSEMA guidance address implications.

Response

The Program specifies content requirements for an Offshore Project Proposal in Section 4.2. This includes the need to identify environmental performance outcomes for the activities that will be carried out for the project. There are two decision points required from NOPSEMA:

         Prior to public consultation – to confirm the Offshore Project Proposal meets requirements and contains sufficient information to allow for the public to make meaningful comment.

         Following public consultation – to confirm the Offshore Project Proposal addresses comments from the public comment period and meets the acceptance criteria.

NOPSEMA may request further written information about any matters to be included in the Offshore Project Proposal following the public consultation period. The Regulations do not prohibit proponents from having more than one opportunity to provide further information. Once NOPSEMA has made a decision to refuse to accept an Offshore Project Proposal and publish a statement of reasons on its website, opportunity for proponents to provide further information has passed, and a new offshore project proposal is required.

 

The Program commits NOPSEMA to preparing guidance for proponents about the Offshore Project Proposal process that address this matter.

Submissions that referred to this issue: 11, 27, 29, 30, 33.

The Taskforce notes that NOPSEMA guidance will outline Offshore Project Proposals in detail.

13

Offshore Project Proposal decision

Submissions from a number of environmental stakeholders raised concerns that proponents may manipulate an open-ended ability to resubmit Offshore Project Proposals and recommended that there should be a provision for a final rejection of a project, or a ‘clearly unacceptable decision’ as exists under the EPBC Act. Some stakeholders questioned whether NOPSEMA could issue a definite ‘no’ decision (for both Offshore Project Proposals and Environment Plans).

Submissions from industry stakeholders questioned whether an Offshore Project Proposal acceptance would provide the certainty required for proponents to make investment decisions, as EPBC Act decisions currently commonly provide this level of certainty.

Response

The Offshore Project Proposal process has been developed to capture offshore projects that may have an impact on a matter protected under Part 3 of the EPBC Act. An Offshore Project Proposal will be able to encompass multiple activities as part of a development project, and its whole lifecycle, although it can apply to discrete activities (e.g. one-off seismic surveys) where proponents opt in to the Offshore Project Proposal process.

An Offshore Project Proposal is indented to provide certainty to proponents for the purposes of investment decision-making. An Offshore Project Proposal is a demonstration that a proposed project will not have an unacceptable impact on the environment, including matters protected under Part 3 of the EPBC Act. It can be used for all petroleum activities and is mandatory for development projects. An Offshore Project Proposal deemed ‘not acceptable’ by NOPSEMA is equivalent to ‘clearly unacceptable’ under EPBC Act.

While an Offshore Project Proposal is intended to provide investment certainty, approval of an Offshore Project Proposal alone does not give the proponent approval for any activity to take place; an accepted Environment Plan must be gained before any activity can commence. The Taskforce is confident the Offshore Project Proposal acceptance under the Program provides the certainty equivalent to that provided under the EPBC Act referral process for financial investment decision-making.

Submissions that referred to this issue: 3, 33.

The Taskforce has taken no further action on this matter.

1.6          Consultation

 

14

Adequacy of streamlining consultation process

Submissions noted the short timeframes associated with consultation on the Program, draft Amendment Regulations and draft Strategic Assessment Report. Other comments noted that information sessions did not have broad enough regional coverage and that there was confusion arising from conducting consultation on both the Regulations and the Program, as well as website technology issues.

 

Response

The Taskforce does not accept the timing and timeframe concerns that have been raised in these submissions. The consultation timeframes were set as required under the EPBC Act, and in line with the Ministerial statement with a clear intention not to consult over the Christmas holiday period. The project timeframe is driven by the Government’s commitment to strengthen Australia’s productivity and international competiveness through delivery of a streamlined framework for environmental approvals processes for offshore petroleum projects.

The Taskforce, established on 21 October 2013, placed a heavy emphasis on communication, with regular updates to interested parties through direct contact (email and telephone) and the Department of Industry’swebsite. The Department sent bulletins using multiple extensive mailing lists sourced from within the Department of Industry, the Department of the Environment and NOPSEMA. The Taskforce also held 13 information sessions covering Hobart, Melbourne, Adelaide and Perth during November and December 2013. In addition, the Taskforce held teleconferences with regional stakeholders in advance of the consultation period to facilitate maximum access to and availability of information within the timeframe available.

The Taskforce also notes that efforts to streamline the regulatory requirements of the EPBC Act and the OPGGS Act began in 2009 following the Productivity Commission Review of Regulatory Burden in the Upstream (Oil and Gas) Sector. In relation to the Strategic Assessment in particular, the Taskforce notes consultation also took place on the draft Terms of Reference in September 2013.

Finally, the Taskforce notes that the Program will be subject to review after one year, and then every five years. The outcome of periodic reviews will be made public. Chapter 10 of the Strategic Assessment Report refers to arrangements for these reviews.

Submissions that referred to this issue: 5, 6, 13,19, 22, 27.

The Taskforce has clarified public consultation as part of the planned reviews of the Program in Chapter 10 (Section10.2) of the Strategic Assessment Report.

15

Consultation on streamlining implementation phase

A range of submissions suggested further consultation was required in relation to the implementation of streamlining. One submission suggested that NOPSEMA have consultation sessions as part of the preparation of guidance notes and establish a multi-stakeholder advisory panel for ongoing input into the process.

Response

The Taskforce has not changed the current position in the Program and Strategic Assessment Reports on this matter. However the Taskforce notes the importance of ongoing consultation and engagement with stakeholders in the development of guidance and implementation of Regulations, as part of good business practice.

The Taskforce also notes that NOPSEMA is developing a communications and implementation strategy in relation to the Program, and suggests that NOPSEMA consider the suggestion to utilise consultations as part of guidance development and a multi-stakeholder advisory panel as mechanisms of ongoing consultation during the streamlining implementation phase.

Submissions that referred to this issue: 5, 24, 31, 33.

The Taskforce has taken no further action on this matter. The Taskforce has suggested that NOPSEMA consider holding consultations and developing a multi-stakeholder advisory panel for ongoing input to Program implementation.

16

Public consultation requirements for Offshore Project Proposals

Submissions presented various views on the public consultation requirements for Offshore Project Proposals, stating that either the proposed four-week minimum was not enough in any circumstance, or that a maximum consultation period be prescribed under the Program, with some suggesting that this should be four weeks.

Submissions also requested clarification on the proposed Regulations and whether the proponent can negotiate the length of consultation with NOPSEMA. Industry stakeholders at information sessions also raised concerns about the uncertainty of timeframes if NOPSEMA were able to determine the length of the consultation beyond four weeks.

Response

The Taskforce considers that early and effective consultation is an expectation of government and community for social licence to operate. The four-week minimum prescribed in the Program was designed to be equivalent to the minimum required under the EPBC Act for assessment of activities that are likely to have an impact on Protected Matters.

In relation to suggestions that a maximum consultation timeframe be prescribed, the Taskforce points to the intention of the Program: to provide for a consultation period, of at least four weeks, but one that is commensurate to the nature and scale of the project, potential risks, and potential impacts. While a maximum timeframe based on known potential impacts and risks of projects may provide certainty for industry, it may not provide for adequate consultation for all proposed projects in the future. The flexible approach of the Program was also designed to provide incentive for early consultation as part of Offshore Project Proposal, which, in consultation with NOPSEMA and demonstrated, might result in a requirement for the minimum four-week public consultation.

NOPSEMA is developing specific guidance for Offshore Project Proposals and will also update its existing consultation guidance in relation to this matter. NOPSEMA will ensure that through these documents it provides a clear indication of potential consultation timeframes that may be appropriate for Offshore Project Proposals in different circumstances, to ensure appropriate opportunity for comment for all stakeholders.

On balance, it is the view of the Taskforce that the minimum four-week consultation period is appropriate, with no maximum set for consultation. In order to increase clarity, the process for determining the consultation period for a specific project has been further developed in the Strategic Assessment Report.

Submissions that referred to this issue: 3, 5, 10, 15, 19, 25, 29, 39.

The Taskforce has revised Chapter 5 (Section 5.3) of the Strategic Assessment Report to clarify processes and consultation requirements under the Program for Offshore Project Proposals.

17

Providing for ‘public interest’ access to consultation.

A number of submissions sought clarification and expansion of the definition of ‘relevant persons’, to ensure that the ‘public interest’ is represented in the assessment process. Some also requested full public consultation for all Environment Plans. One submission suggested narrowing the definition of ‘relevant persons’.

Response

The Taskforce notes that early and effective consultation is an expectation of governments and the community as part of maintaining social licence to operate for industry. However given concerns about ‘stakeholder fatigue’ from both environmental groups and industry there is a need to ensure consultation processes are efficient. From the Taskforce’s perspective this means that public interest access to offshore assessment and decision-making must meet society’s expectations but be efficient at the same time. Consultation arrangements for the Program are described in Chapter 5 of the Strategic Assessment Report. The Taskforce is of the view that on balance, the arrangements described are appropriate and that no change is required to the Program or Strategic Assessment report. The reasons for this are as follows.

First, the Offshore Project Proposal process provides for four weeks minimum public consultation for assessment of all activities that are likely to have an impact on matters protected under the EPBC Act, in line with the minimum requirement under the EPBC Act.

Secondly, in relation to Environment Plans, concern about absence of public access may arise from the definition of ‘relevant persons’ (as defined in the Environment Regulations) and doubts about whether interest groups qualify under the definition. However the Taskforce points out that environmental NGOs, who have provided submissions on this issue, can and have previously qualified as ‘relevant persons’ for the purpose of Environment Plan consultation. The Taskforce also notes the extent and effectiveness of consultation, as a Titleholder must submit a report to NOPSEMA on all consultations between the operator and any relevant person. This must include an assessment of the merits of any objection or claim and the Titleholders response. NOPSEMA is unable to accept an Environment Plan unless these requirements are met.

Submissions that referred to this issue: 3, 5, 6, 10, 13, 19, 21, 22, 27, 28, 29.

The Taskforce has not actioned any change to existing provisions.

18

Risk of stakeholder ‘consultation fatigue’

Submissions from all stakeholder groups (industry, fishing industry, environmental NGOs and government) noted the general and increasing volume of consultation required in relation to offshore petroleum exploration and development and described it as ‘consultation fatigue’. It was suggested that this could possibly increase under the Program. A number of submissions suggested government funding for environmental NGOs may assist in managing stakeholder fatigue.

Submissions also suggested that the streamlining process presents an opportunity to make improvements in the traditional consultation process, by suggesting a more strategic approach be adopted rather than commenting on individual Environment Plans. The work between the industry peak body, the Australian Petroleum Production and Exploration Association (APPEA) and fishing interests was identified as a process that could lead to the development of a framework for effective engagement with fishing stakeholders.

Response

 

The Taskforce is of the view that early engagement is a clear expectation of government and community to maintain a social licence to operate for industry, and is good business practice.

The Taskforce agrees that development of strategic and efficient approaches to consultation will be of clear benefit to both industry and stakeholders and encourages both parties to pursue such arrangements under the Program. The Taskforce notes that NOPSEMA guidance on consultation is to be updated to reflect the amendments to the Regulations and introduction of the Offshore Project Proposal process.

The Taskforce recommends that NOPSEMA consider its role in encouraging strategic and streamlined consultation, as appropriate, for example through the development of frameworks for engagement in relation to the implementation of the Program (see also Issue 15 – consultation arrangements for implementation).

Submissions that referred to this issue: 13,15, 23, 24, 28, 29, 33.

The Taskforce has amended Chapter 5 (Section 5.3) of the Strategic Assessment Report to make reference to the use of strategic consultation under the Program.

 

The Taskforce has also recommended that NOPSEMA encourage effective, strategic and streamlined consultation in updated guidance.

1.7          Transparency

 

19

Notifications and publication of documents

Comments on transparency varied between stakeholder groups. Industry submissions raised concerns in relation to the potential requirement to publish commercial-in-confidence information as part of an Offshore Project Proposal. They also suggested that there was an increase in regulatory burden where additional information is to be included in Environment Plan summaries.

Environmental NGOs and fishing industry stakeholders sought increased transparency through full publication of Environment Plans with relevant data and supporting evidence to also be provided.

Several submissions from all groups recommended that NOPSEMA provide notifications of proposals, revisions and decisions via an electronic system that relevant persons could register to receive.

 

Response

The Program provides for full publication of Offshore Project Proposals in line with expected transparency arrangements for matters that are likely to have an impact on a matter protected under Part 3 of the EPBC Act.

Further, the new notification provision and expanded Environment Plan summary contents both seek to ensure adequate information is provided in the public domain about how environmental outcomes are being achieved under the Program as under the EPBC Act. The Program promotes transparency in these processes through notification requirements, clear acceptance criteria, and publication of information. Section 5.4 of the Strategic Assessment Report and sections 4.5 and 5.5 of the Program Report provide details of these processes.

The Taskforce believes that these requirements deliver an appropriate level of transparency while maintaining protection of commercially sensitive information and managing regulatory burden. The Taskforce supports the suggestion that NOPSEMA provide notifications via an electronic system, and notes that NOPSEMA is investigating various mechanisms for effective notification as part of its implementation strategy.

Submissions that referred to this issue: 5, 11, 18, 21, 22, 27, 28, 29.

The Taskforce has recommended that NOPSEMA pursue an electronic notifications system.

20

Feedback to agencies providing inputs

One submission noted that it is not always clear how information provided to a Titleholder in the course of consultation is incorporated into resulting Environment Plans. The submission sought amendment or clarification such that Titleholders should be required to provide written feedback to stakeholders following consultation.

Response

The Taskforce considers that the ongoing relationship between titleholders and ‘relevant persons’ is paramount in ensuring the effectiveness of the Program, but is the responsibility of the titleholder. The Taskforce notes that where agencies or stakeholders request written feedback from titleholders, good practice would indicate that a titleholder should provide such feedback. The Taskforce considers that this is a matter best addressed through guidance and ongoing engagement between the titleholder and relevant persons, and recommends that NOPSEMA incorporate this issue into its updated guidance.

Submissions that referred to this issue: 14.

The Taskforce has recommended NOPSEMA address the issue of provision of responses to relevant persons in updated guidance.

21

Publication of statements of reasons for decisions

A number of submissions sought the publication of statements of reasons for all decisions – for both accepting and refusing to accept Offshore Project Proposals and Environments Plans. The submissions suggested that these statements should be made available on request as a minimum.

Response

Transparency arrangements under the Program are discussed in Chapter 5 of the Strategic Assessment Report. As the Strategic Assessment Report points out, as the Program is an objective-based regime, whereby the acceptance criteria effectively provide ‘statements of reason’ where an offshore proposal or Environment Plan is accepted. This is because the regulator makes its decision on the basis that all the criteria have been met by the submission. This is in combination with publication of the whole Offshore Project Proposal or the Environment Plan summary.

In the event that an Offshore Project Proposal is refused acceptance, NOPSEMA will publish a notification and statement of reasons for the decision. If an Environment Plan is refused acceptance, NOPSEMA will publish a notification of the decision.

The Taskforce believes that these arrangements are appropriate and commensurate with the EPBC Act, in relation to matters protected under Part 3. Chapter 5 of the Strategic Assessment Report has been updated for clarity.

Submissions that referred to this issue: 5, 22, 28.

The Taskforce has amended Chapter 5 (Section 5.2) of the Strategic Assessment Report to provide more information in relation to statements of reasons and the relevance of acceptance criteria in the event that a proposal or plan is accepted.

1.8          NOPSEMA Processes

22

Use of condition-setting powers

Environmental stakeholders suggested that NOPSEMA, in relation to its decision-making for matters protected under Part 3 of the EPBC Act, should be specifically empowered to make conditions about these matters. Submission 22 also suggested that NOPSEMA’s lack of application of condition-setting powers is limiting the ability to drive industry innovation and risk reduction, and should be used if the objective-based regime does not achieve environmental improvement.

More generally, stakeholders suggested that condition-setting for Environment Plans should be subject to consultation with the proponent (as is the case under the EPBC Act).

Response

NOPSEMA has the regulatory ability to accept an Environment Plan either in part, or with limitations or conditions (Section 5.6.6 of the Program Report; Regulation 10(6)). The use of this regulatory power is detailed in NOPSEMA’s Environment Plan Assessment Policy, available on NOPSEMA’s website.[29]

NOPSEMA’s general policy is that the titleholder should be able to address any requirement considered necessary for effective management of environmental risks and impacts in their Environment Plan submission, and not rely on the regulator to set conditions. However, it is acknowledged that this may not be the case in all circumstances, and NOPSEMA has, from time to time, exercised its powers under Regulation 10(6). 

In determining whether to accept a submission in part with limitations or conditions, NOPSEMA, as a matter of good practice, engages with the titleholder on the proposed decision.

Submissions that referred to this issue: 22, 27.

The Taskforce has taken no further action on this matter.

23

NOPSEMA decision-making

Stakeholders suggested certain modifications and clarifications for the decision-making process, including that NOPSEMA take account of public comments in an Offshore Project Proposal acceptance decision, and that the Program should clarify that an Environment Plan will not be ‘accepted’ where an impact on a threatened species habitat is not acceptable.

A further submission suggested that NOPSEMA should consult with the relevant state or territory government in its assessment and decision-making processes, as provided for in the EPBC Act.

Response

Offshore Project Proposal Consultation

 

The proponent of an offshore project proposal is required to address all comments raised regarding their proposed activity, and provide a full transcript to NOPSEMA of all consultations. The Offshore Project Proposal also places the onus of addressing public submissions on the proponent by requiring that they assess the merits of any objections or claims made in the submissions and provide a statement of the response to any claims, including any changes to the proposal as a result of the submissions.

NOPSEMA will not accept an Offshore Project Proposal if the assessment of the submissions, and the proposed response by the proponent is not adequate.

Environment Plan Acceptance

An Environment Plan must describe the environment in which the proposed activity will be taking place, including any environmental sensitivity. This broad definition of the environment includes not just threatened species, but also key components of their habitat. The Environment Plan must also detail how the relevant elements of the environment may be impacted by the proposed activity and what control measures will be in place to reduce the impacts to acceptable levels.

NOPSEMA cannot accept an Environment Plan unless the demonstrations required by the acceptance criteria are met, including that impacts and risk will be reduced to acceptable levels.

Consultation with state/territory agencies

In the preparation of an Environment Plan, a titleholder must consult with each agency of a state/territory to which the activities may be relevant; and with the department of the responsible state/territory Minister. The results of this consultation are required to be documented in the Environment Plan.

NOPSEMA can and does consult with relevant state/territory agencies in relevant circumstances. There are administrative arrangements (in the form of Memoranda of Understanding or other agreements) in place with a number of jurisdictions, which are reviewed and updated from time to time.

Submissions that referred to this issue: 19, 20, 36.

The Taskforce has taken no further action on this matter.

24

Verification process for information provided by a proponent

Submissions suggested that NOPSEMA must consider whether the proponent’s determination of risk (and significance) is acceptable to NOPSEMA and that reporting requirements under the Program rely on self-reporting by proponents. While it was noted that NOPSEMA administers a monitoring and inspection process, it was recommended that there be a process of verifying data submitted.

Response

NOPSEMA’s Environment Division is staffed by suitably qualified and experienced personnel across a range of disciplines including science and regulatory policy. They have extensive experience in environmental management in the petroleum sector enabling them with the appropriate skills to critically analyse information provided in Titleholder submissions and reports.

In addition NOPSEMA also retains the capacity and statutory ability to either independently verify information and claims contained in titleholder submissions, or request that the Titleholder provide further evidence in support of the information or claims.

Submissions that referred to this issue: 3, 29.

The Taskforce has taken no further action on this matter.

1.9          Compliance and enforcement

 

25

Penalties for Protected Matters compared to EPBC Act.

Several submissions expressed concern that the penalties under the Program were reduced compared to those in the EPBC Act, and that the provisions under the OPGGS Act were not sufficient as they had no focus on matters of national environmental significance (MNES).

Response

Part B (Section 6) of the Program Report and Chapter 6 of the Strategic Assessment Report describe compliance and enforcement under the Program. NOPSEMA has a wide range of graduated response options available to it under the Program. NOPSEMA can also facilitate enforcement under the EPBC Act.

The Taskforce also notes that, if the Program is endorsed and actions or classes of actions approved under Part 10 of the EPBC Act, the penalties under the EPBC Act still apply where the proponent is found to have incurred a significant impact on a matter protected under Part 3 of the EPBC Act and is not acting in accordance with the endorsed Program. This means that, contrary to the assertion that penalties would be reduced under the Program, penalties under the Program and the EPBC Act will continue to apply.

The Taskforce acknowledges that this issue was not clearly explained in the Strategic Assessment report and has reviewed and amended the text to clarify this.

Submissions that referred to this issue: 3, 10, 19, 21, 22, 28.

The Taskforce has clarified Chapter 6 (Section 6.1) of the Strategic Assessment Report to reflect that EPBC Act penalties continue to apply if a proponent does not act in accordance with the Program and, as a result, cause a significant impact on a matter protected under Part 3 of the EPBC Act.

26

Public reporting of compliance and enforcement for Protected Matters

Submissions suggested that the reporting of compliance and enforcement action in relation to environment performance is not currently sufficiently detailed and should be more transparent as NOPSEMA will have additional enforcement responsibilities relating to EPBC Act Protected Matters under the Program.

Response

The Taskforce is of the view that performance reporting is consolidated and more readily accessible under the Program. NOPSEMA publishes annual industry performance reports and quarterly KPI update reports on its website outlining key matters in relation to industry’s performance against regulatory requirements. NOPSEMA also includes compliance and enforcement reporting as part of the published Annual Report. Chapter 9 of the Strategic Assessment Report refers to reporting arrangements.

The Taskforce also notes that the Program will be subject to review after one year, and then every five years, in relation protection of matters under Part 3 of the EPBC Act, including relevant compliance and enforcement. The outcome of these reviews will be made public. Chapter 10 of the Strategic Assessment Report refers to arrangements for these reviews.

Further, both the NOPSEMA Annual Report and annual plan are published documents. The annual plan is a statutory requirement for NOPSEMA to publish an operational plan for its activities over the forward 12 months. The Annual Report is also a statutory requirement for NOPSEMA to publish reporting on its general activities over the previous 12 months.

Submissions that referred to this issue: 3, 28.

The Taskforce has:

·         amended Chapter 9 (Section 9.1) of the Strategic Assessment Report to include reference to industry performance reporting.

 

·         amended Chapter 10 (Section 10.2) of the Strategic Assessment Report to clarify that the outcome of Program reviews will be made public.

1.10       Cost recovery

 

27

Adequacy of NOPSEMA resourcing

Several submissions from both environmental and industry perspectives noted the importance of NOPSEMA being adequately resourced to ensure it can implement and deliver the commitments of the Program and to ensure there are no unnecessary delays to assessments during the transition phase and in the longer term. NOPSEMA, in its submission, also noted that it must be able to levy all Environment Plans to ensure efficient and effective regulation.

Submissions also:

·         questioned whether NOPSEMA had adequate expertise and resourcing, and

·         suggested that NOPSEMA’s levies may need to be increased to ensure adequate resourcing.

Response

The Taskforce notes that NOPSEMA is a fully cost-recovered agency. Its activities and functions are funded through levies on the petroleum industry and/or a fee-for-service arrangement. This ensures that NOPSEMA’s resourcing is consistent with the level of regulatory activity required and provides the flexibility to manage the changing requirements presented by the implementation and management of the Program.

The arrangements for levies are provided for under the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Act 2003 and the Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Regulations 2004. Specifically, assessments of Environment Plans are funded through an Environment Plan activity levy, and compliance inspections are funded through an Environment Plan compliance levy. The specific levy amounts under these arrangements are set out and approved by the Australian Government on a regular basis through a Cost Recovery Impact Statement (CRIS). The CRIS development process must include stakeholder consultation.

For the proposed Offshore Project Proposals, a fee-for-service will apply according to time required to undertake assessment. NOPSEMA already applies a fee-for-service arrangement for early engagement on Safety Cases under the Offshore Petroleum and Greenhouse Gas Storage (Safety) Regulations 2009. NOPSEMA will issue guidance in relation to the proposed fees for Offshore Project Proposal assessment by the end of February 2014 (prior to commencement of the amended Regulations).

In relation to NOPSEMA’s human resourcing, the Taskforce notes that the cost recovery model ensures NOPSEMA has the resources to ensure access to and maintenance of appropriate and specialist environmental expertise, and the ability to seek external expertise on a case-by-case basis. The Program also provides that NOPSEMA will enter into administrative arrangements with the Department of the Environment to ensure appropriate information sharing for implementation of the Program. The Taskforce notes that as of January 2014 NOPSEMA and the Department of the Environment have commenced preparatory work in relation to implementation activities.

Submissions that referred to this issue: 8, 22, 25, 33, 35.

The Taskforce has:

·         clarified Sections 4.4 and 5.2 of the Strategic Assessment Report to explain NOPSEMA’s cost recovery arrangements under the Program, in particular to ensure strong environmental safeguards.

 

·         clarified Section 9.3 of the Strategic Assessment Report to address transitional matters including NOPSEMA’s ability to call upon external expertise in the course of exercising its functions.

 

1.11       Environment Regulations review

28

Implications of change from ‘Operator’ to ‘Titleholder’

NOTE: This change is to implement a policy outcome of the 2012 Environment Regulations Review and is not for consideration as part of the Strategic Assessment.

A concern raised by several submissions was the potential for unintended consequences arising from the transfer of responsibility from the ‘operator’ to a ‘titleholder’, in relation to activities undertaken across multiple title areas held by different titleholders. In particular, submissions raised the potential for the unintended consequences this may have for multi-client seismic operators, with concerns the new process would require multiple Environment Plans to be submitted for a single survey and would not allow for gaps in seismic schedules to be easily filled.

Response

The proposed amendments to the Environment Regulations include a change from ‘operator’ to ‘titleholder’ as the responsible entity for submission of, and compliance with, an Environment Plan (and also more generally responsibility for compliance with the requirements of the Environment Regulations). The concept of an ‘operator’ will be removed from the Environment Regulations.

The Regulations do not prevent a single activity being carried out across multiple title areas, as the Regulations are activity-based, rather than title-based. In these cases, the titleholder for each title area could sign their name to a single Environment Plan for the activity to be submitted to the Regulator on behalf of all the titleholders (with the name and contact details for each titleholder included in the Environment Plan). The Taskforce intends to clarify this in the Explanatory Statement supporting the regulatory amendments, which will be released publicly at the end of February 2014.

The majority of multi-client surveys are undertaken using a combination of petroleum special prospecting authorities (SPAs) and petroleum access authorities (AAs) held by the survey operator. Under the proposed regulatory amendments holders of SPAs and/or AAs, as ‘titleholders’ for the purposes of the Regulations, will be responsible for submission of Environment Plans for activities undertaken under those titles. In practice, this will mean the process for submitting Environment Plans for multi-client surveys undertaken under those titles will be simplified, as no separate nomination of an operator for the activity will be required.

This process is further supported by amendments allowing applicants for SPAs and AAs to submit Environment Plans for acceptance prior to the grant of the title. This will ensure that if an addition to a survey is proposed, the proponent may submit or revise an Environment Plan once they have lodged an application for the SPA or AA with the National Offshore Petroleum Titles Administrator (NOPTA). Further, if the plan is accepted by NOPSEMA prior to grant of the title, the survey can proceed as soon as the SPA or AA is granted. This will maintain the flexibility to add additional areas to a multi-client seismic survey.

Submissions that referred to this issue: 15, 27, 29, 33.

Taskforce to clarify titleholder/operator transition in the Explanatory Statement supporting the regulatory amendments.

 

29

Ambiguity of definitions, requiring further explanation and guidance from NOPSEMA

A number of submissions requested greater clarity and clear consistency between the Strategic Assessment Report, the Program, the amended Regulations and existing processes for key concepts such as: ‘offshore project’, ‘Offshore Project Proposal’,  ‘development project’, ‘Brownfield’, ‘Greenfield’, ‘whole-of-lifecycle’, ‘acceptable level’, and  ‘credible scenario’.

Response

The Taskforce notes the request for greater clarity and consistency of key terms in the Program, Strategic Assessment Report and the amended Environment Regulations. The Taskforce will address and clarify definitions in the amended Environment Regulations where appropriate and further information will also be provided in the Explanatory Statement. These documents will be released publicly by the end of February 2014.

Please refer to Issue 5 for information of definition of terms.

 Submissions that referred to this issue: 11, 15, 27, 29, 30, 31.

 

Taskforce to clarify definitions in the amended Environment Regulations and Explanatory Statement supporting the regulatory amendments.

 

30

Definition of ‘petroleum activity’

NOTE: This change is to implement a policy outcome of the 2012 Environment Regulations Review and is not for consideration as part of the Strategic Assessment.

A number of submissions sought further clarification about the proposed definition of “petroleum activity”, arguing the new definition is still quite broad and ambiguous, and may capture work program commitments. The submissions stated the definition of ‘petroleum activity’ should be limited to that of exploration and production activities undertaken directly for the purpose of exploring for or producing hydrocarbons, primarily seismic surveying and the drilling of wells. Several of the submissions sought the specific exclusion of certain low risk activities in the definition. The activities suggested included geotechnical/geophysical surveys, environmental and oceanographic surveys, and airborne surveys.

Response

 

The review of the Environment Regulations considered the definition of ‘petroleum activity’ with a view to clarifying and reducing the scope of the definition, to ensure it would not potentially capture ordinary maritime activities. This amendment is also linked to the policy decision to transfer responsibility for compliance with the Environment Regulations from the ‘operator’ to the ‘titleholder’ (discussed above in Issue 28), to ensure the titleholder is responsible for managing the environmental impacts and risks created by the activities they undertake, and reflecting the titleholder’s responsibility for compliance with environmental obligations under the OPGGS Act.

The new definition removes the reference in the current Regulations to ‘any activity relating to petroleum exploration or development which may have an impact on the environment’, significantly narrowing the scope of the definition. The new definition also links petroleum activities directly to the rights conferred on a titleholder under the OPGGS Act by a title, or obligations imposed on a titleholder by or under the OPGGS Act. The Department of Industry considered a list of indicative exclusions from the definition, including proposed exclusions provided by industry in the course of consultations on the review. However, many of the proposed exclusions would already fall outside the scope of the amended definition; therefore to expressly include them would create regulatory uncertainty as to the definition itself. The Taskforce considers that the new definition of ‘petroleum activity’ sufficiently reduces the scope for inclusion of activities that should not require an Environment Plan under the Regulations, and therefore has not included a list of exclusions within the definition.

The Taskforce intends to further clarify this in the Explanatory Statement supporting the regulatory amendments, which will be released publicly at the end of February 2014. This will also include an explanation of the application or otherwise of the definition to work program commitments.

Submissions that referred to this issue: 11, 15, 24, 25, 27, 29, 30, 31, 33, 34,36. 

 

Taskforce to clarify definitions in the amended Environment Regulations and Explanatory Statement supporting the regulatory amendments.

 

31

Monitoring discharges

NOTE: This change is to implement a policy outcome of the 2012 Environment Regulations Review and is not for consideration as part of the Strategic Assessment.

Several submissions expressed concern at the removal of prescriptive requirements regulating discharges of produced formation water. On the other hand, other submissions supported the removal of the prescriptive requirements. The latter submissions, however, noted the potential for the regulator to push goals beyond what is accepted ‘good oilfield practice’ around the world.

Response

The regulations relating specifically to the measurement and management of petroleum discharged in produced formation water did not reinforce the principles of reduction of environmental impacts and risks to ALARP or an acceptable level. The monitoring of all discharges, including produced formation water, is required under the amended sub-regulation 14(7), which requires a titleholder to provide for monitoring of all emissions and discharges sufficient to assess whether the environmental performance outcomes and standards in the Environment Plan are being met. In accordance with the acceptance criteria for an Environment Plan, arrangements relating to discharges of produced formation water will be sufficient if they demonstrate that discharges will be managed to ALARP and an acceptable level.

 Submissions that referred to this issue: 10, 15, 21, 24.

The Taskforce has taken no further action on this matter.

32

Incident notification requirements

NOTE: This change is to implement a policy outcome of the 2012 Environment Regulations Review and is not for consideration as part of the Strategic Assessment.

A submission suggested the existing requirement to notify the regulator of all reportable incidents within two hours was unrealistic and that the Environment Regulations be amended to align with the Safety Regulations, where the notification requirement is “as soon as practicable” after the incident. Specific request for clarification around the timing of written notifications was also made.

A further submission asked what arrangements would be in place to ensure NOPSEMA is available 24 hours a day, 7 days a week to receive oral notifications of reportable incidents.

Response

The titleholder must orally notify the regulator within two hours of any incident relating to an activity that has caused, or has the potential to cause, moderate to significant environmental damage, and provide a written report to the regulator within three days. This will ensure quick and appropriate action in the event of a reportable incident, which will in turn provide the public with confidence that an incident is being managed appropriately. On this basis, it is not appropriate to reduce the current incident notification requirement.

The Taskforce notes that NOPSEMA has an incident response phone number (prominent on NOPSEMA’s website), which is manned by a duty officer 24 hours a day, 7 days a week.

Submissions that referred to this issue: 11, 30, 36.

The Taskforce has taken no further action on this matter.

33

Revision of Environment Plans for decreased environmental risk

A submission recommended a titleholder way wish to submit a proposed revision of an Environment Plan if there has been a significant decrease in an existing environmental impact or risk.

Response

The Environment Regulations require a titleholder to submit a proposed revision of an Environment Plan where there is any significant new environmental impact or risk, or an increase in an existing environmental impact or risk, not already provided for in the Environment Plan in force for the activity. Additionally, a titleholder must submit to the regulator a revision of the Environment Plan at least every five years. In circumstances where there is a decrease in risk (but not a new risk), the in-force Environment Plan would address the nature of that risk, albeit at a higher level. Requiring a titleholder to submit a proposed revision of an Environment Plan for a decrease in risk will increase the regulatory burden on industry, without delivering a measurable improvement in environmental standards. Therefore, the Taskforce does not propose an amendment to the Regulations to this effect.

Submissions that referred to this issue: 7.

The Taskforce has taken no further action on this matter.

1.12       Reporting

34

Reporting of all environmental damage

A submission recommended that the Program require notification of all environmental damage. The submission expressed concern that the Program requires notification of incidents ‘only in relation to moderate to significant environmental damage’, and recommended there be an obligation to notify all environmental damage. The submission noted, however, that damage other than moderate to significant need not be notified with the same urgency.

Response

The Program already requires notification of all reportable incidents (reportable incident, for a titleholder undertaking an activity, means an incident relating to the activity that has caused, or has the potential to cause, moderate to significant environmental damage). 

In addition to the notification requirements for incidents in relation to moderate to significant environmental damage, titleholders must provide a monthly report of ‘recordable incidents’. A ‘recordable incident’ is any instance in which the titleholder has breached an environmental performance outcome or standard under an accepted Environment Plan. The report must contain a record of all recordable incidents during the month, all material facts and circumstances concerning the incidents, any action to avoid or mitigate adverse environmental impacts, corrective action that has been or will be taken, and action taken to prevent similar incidents in the future. A titleholder must also prepare and submit a report detailing its environmental performance for an activity no less than annually.

The Taskforce is confident that the Program, as currently drafted, provides an adequate level of notification for environmental damage.

Submissions that referred to this issue: 3.

The Taskforce has not actioned any change to current provisions.

1.13       Cross-jurisdictional issues

35

Integration of the Program with state assessment processes (state waters and land)

Submissions from industry expressed concern about the integration of the NOPSEMA offshore streamlining process and state assessment processes for state waters, as well as the broader bilateral COAG environmental approvals streamlining processes for linked land-based activities. It was suggested that unless these issues were resolved there could be duplication and added complexity, which would increase the cost and time associated with projects.

Submissions sought further information and clarification around how cross-jurisdictional approval processes will be managed. One submission also suggested that the alignment of state-based assessments with the EPBC Act impact-based approach (compared to the activity-based approach of the Program) could add to the regulatory burden and that this aspect needed careful consideration. This issue was identified as critical to the success of the streamlining reforms by a number of submissions, which argued for a longer implementation lead-time to ensure the impacts on business from the transition were minimised. Integration in relation to implementation of compliance requirements of the EPBC Act and OPGGS(E) Regulations was also identified as a specific issue.

Response

The Strategic Assessment is one step of a multi-pronged government approach to streamlining of environmental approvals. The one-stop-shop Commonwealth–state/territory streamlining reform, which as a Council of Australian Governments (COAG) process, is necessarily more complex and time consuming. This means that the full benefits will be gradually realised as each tranche of streamlining is completed. The intention, however, is to achieve the best offshore streamlining outcome possible and it has been progressed as a stand-alone initiative to achieve timely and tangible progress for the offshore industry sector as a priority. Integration with other related processes, including alignment of regulatory approaches, will remain a challenge for all parties – but one that will be subject to further discussions with industry as these processes progress.

States may currently confer powers to NOPSEMA under the OPGGS Act in relation to state waters and this would add to the effectiveness of offshore streamlining. The Program anticipates this possibility and has been developed to enable this, should it occur, with as little regulatory impact as possible.

The Taskforce notes the concerns raised and has reviewed the Program and Strategic Assessment Reports in relation to this issue, to ensure clarity. Other responses relevant to this issue can be found in Transitional Arrangements (Issue 36, 37) and Compliance and Enforcement (Issue 25, 26).

Submissions that referred to this issue: 11, 15, 17, 22, 27, 29, 33, 35, 36, 38.

The Taskforce has reviewed and clarified Section 4.3 of the Strategic Assessment Report.

The Taskforce also recommends that the Department of Industry and the Joint Authority continue to encourage states and the Northern Territory to consider conferral of environmental management functions.

1.14       Transitional arrangements

36

Delayed implementation of the Program

Many industry stakeholders sought clarification of matters relating to the implementation of the Program, noted the scale and complexity of the proposed regulatory amendments and recommended a delayed implementation of these provisions, to ensure the greater understanding of the Program and minimise any unintended consequences.

Response

The Taskforce notes that streamlining offshore environmental approvals will reduce regulatory burden on industry while maintaining existing environmental safeguards, in accordance with the Government’s agenda to provide a one stop shop for environmental approvals, as well as its broader deregulation agenda.

The Taskforce also notes the Government’s commitment to streamline offshore environmental approvals by March 2014.

The Ministerial announcements and the Strategic Assessment Agreement indicate the Government’s commitment to completing the Strategic Assessment by end February 2014. The Taskforce is continuing to work towards this commitment.

Submissions that referred to this issue: 15, 17, 24, 27, 29, 31, 33, 35.

The Taskforce has not actioned any changes in relation to this issue.

37

Further clarity and guidance is required about transition and implementation matters

Several industry submissions identified a number of aspects of implementation and transitional arrangements as a source of significant uncertainty, which they suggest require further clarification in the Program or as part of NOPSEMA guidance.

These included:

·         the transfer of EPBC Act conditions to NOPSEMA from existing EPBC Act approvals;

·         compliance and enforcement arrangements between the Department of the Environment and NOPSEMA); and

·         arrangements for ‘brownfields’ projects approved prior to the EPBC Act.

A number of submissions also sought continued engagement with the Taskforce or NOPSEMA to assist with implementation and to develop shared expectations.

Response

The Taskforce notes that, under the Program, NOPSEMA has committed to developing and updating a suite of guidance documents to assist industry and other stakeholders to understand the Program and assist in the transition period. The Taskforce notes that NOPSEMA’s approach to the preparation of guidance seeks to involve stakeholders, as appropriate, in order to ensure their continuous relevance and improvement. The Taskforce also notes that NOPSEMA will continue undertake information sessions and workshops with industry, as required, to ensure industry preparedness for implementation.

In relation to existing EPBC Act conditions and approvals, the Taskforce recommends that the Department of the Environment provide information to industry and other stakeholders in relation to compliance and enforcement for existing EPBC Act approvals and conditions.

Submissions that referred to this issue: 15, 17, 24, 27, 29, 31, 33, 35.

The Taskforce recommends that the Department of the Environment clarify transitional matters in relation to existing EPBC Act approvals and conditions.

 

The Taskforce also notes NOPSEMA is preparing guidance outlining implementation and transitional arrangements.

1.15       Review

38

Review of NOPSEMA decisions and procedural fairness

A number of submissions mentioned the issue of lack of availability of procedural review of NOPSEMA decisions (e.g. Environment Plan withdrawal) in the context of procedural fairness.

Response

The Taskforce notes that the opportunity for procedural review of regulatory decisions under the Program exists and is the same as that under the EPBC Act. This matter is already addressed in the Strategic Assessment Report. Section 5.5 of the Strategic Assessment Report states that procedural reviews can be sought under the Administrative Decisions (Judicial Review) Act 1977. Industry stakeholders would have standing to bring proceedings under this Act if they consider that they are aggrieved by a NOPSEMA decision. The Taskforce notes that neither the Program nor EPBC Act has the facility for an independent ‘merit’ review of decisions.

Submissions that referred to this issue: 20, 29.

The Taskforce has reviewed and clarified Section 5.5 of the Strategic Assessment Report with respect to this issue.

 

39

Need for extended standing provisions to provide for public access

Several submissions from environmental NGOs suggested that there was a need for the Program to have extended standing provisions, as is the case for the EPBC Act. Without this, they suggested, access to a review of decisions by public interest groups would be limited.

Response

The Strategic Assessment Report discusses judicial review and standing in Section 5.6, which points out that while the Program does not have extended standing as for the EPBC Act, current approaches by courts to standing of environmental groups in relation to the Administrative Decisions (Judicial Review) Act 1977 have been liberal. Environmental groups have been able to receive standing when they have been able to establish an organisational eminence in the particular field and a close connection between the issue in dispute and the organisation’s activities. The Taskforce suggests that it may be indicative of standing that many environmental NGOs have established themselves as ‘relevant persons’ under the OPGGS Act in terms of consultation on Environment Plans by the offshore industry. This has been based on their expertise in and information they collect on marine conservation and related matters (refer also to discussion re ‘relevant persons’ in relation to consultation on Environment Plans).

The Taskforce is therefore of the view that extended standing is not required under the Program.

Submissions that referred to this issue: 10, 19, 21, 22, 28.

The Taskforce has not actioned any changes in relation to this issue.

40

Review of Program operation

Several submissions from both industry and environmental NGOs, commented about the importance of reviewing the Program. Some mentioned the need for further clarification and others mentioned the need for public consultation to be part of a program review.

Response

The Taskforce notes that Part D of the Program Report and Section 10 of the Strategic Assessment Report outline the agreed arrangements for review of the Program. These in