Australia’s revamped offshore oil & gas laws go live

Australia’s offshore oil and gas laws were amended in September 2021, and key changes went live on 2 March 2022.  A new change of control test will make oil and gas M&A in Australia more complex, and past, present and potential future titleholders will need to carefully consider their exposure to new “trailing liability” for decommissioning costs.

Extensive amendments to the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (Cth) (the Act) that regulate changes of control of titleholders as well as introducing trailing liability for decommissioning costs that were passed in September 2021 came into effect on 2 March 2022. A revamped set of guidelines were also issued by the Department of Industry, Science, Energy and Resources, including new guidelines on transfers, dealings, change in control and other titleholder transactions (the Transfer Guidelines) and trailing liability for decommissioning of offshore petroleum property (the Trailing Liability Guidelines).

What’s changed?

The amendments to the Act address two key areas which will be of interest to current and prospective operators and investors in Australia’s offshore sector, as well as their financiers and advisors:

• changes of control of a titleholder (as opposed to a title itself) are regulated for the first time; and
• former titleholders and their related parties will retain trailing liability for decommissioning.

The regulators and the relevant federal Minister have also been given enhanced information gathering powers to enable ongoing suitability assessment of parties engaged in or seeking to participate in Australia’s offshore sector and monitor compliance with the Act.

The trailing liability provisions have retrospective effect from 1 January 2021.

A brief overview of the substance of the changes follows, together with comment on their impact and what you need to do in response.

Change of control

The approval of NOPTA (the National Offshore Petroleum Titles Administrator) is required for any change of control of a registered holder of a petroleum or greenhouse gas title, regardless of the percentage interest held in the title. More controversially, the threshold for “control” is set at 20%. NOPTA’s approval must be obtained in order for the change in control to take effect, but the approval will be valid for only a nine month period and can be revoked on a change of circumstances. A change of control also includes cessation of control, meaning that both entry into and exit from an offshore project – or an investment higher up a corporate chain – requires NOPTA approval. The Transfer Guidelines state that change of control applications should be made at least six months before the change of control is intended to take effect.

In addition to the control test, new tracing provisions which are similar to those in the Foreign Acquisitions and Takeovers Act 1975 (Cth) (FATA) look upwards from the titleholder using the same 20% threshold and with seemingly infinite scope. What constitutes control is subtly different to the equivalent regimes under FATA and the Corporations Act 2001 (Cth). Importantly, there are no exceptions, and no mechanism for introducing exceptions. 

Civil and criminal penalties may apply for a change of control occurring without NOPTA’s approval, and a breach of these provisions is grounds for cancellation of the relevant title.

Trailing liability and the call-back

NOPSEMA’s (the National Offshore Petroleum Safety and Environmental Management Authority) remedial direction powers under the Act have been expanded significantly to allow the “call back” of previous titleholders and their related parties, where a current or immediate former titleholder is unable to meet its decommissioning obligations.

The range of persons that may be “called back” is extensive and includes not only former titleholders and their related bodies corporate, but any person that NOPSEMA or the relevant federal Minister determines has, or could have, significantly benefitted (financially) from the operations, or has been in a position to influence the extent of another person’s compliance with their obligations under the Act, or has acted jointly with a titleholder in relation to operations under the relevant title. In practice, this could catch royalty holders, financiers, employees and advisers, as well as titleholders themselves. The Trailing Liability Guidelines shed some limited light in stating that all joint venturers are within scope, as potentially are ‘major’ shareholders and directors, but not people who are paid ‘market value’ for work (e.g. employees, contractors or lenders – although no colour is provided on the treatment of secured lenders enforcing their security or their security agents).

While the Explanatory Memorandum and the Trailing Liability Guidelines note that these enhanced powers are intended to be used as a last resort where a current or immediate former titleholder cannot meet their decommissioning obligations, this is not reflected in the Act.

The Trailing Liability Guidelines state that individuals will generally only be issued remedial directions where there is no former titleholder or a related body corporate who is capable of undertaking the works.

The Trailing Liability Guidelines also state that when considering whether to issue a remedial direction on a current or former titleholder with respect to decommissioning works, NOPSEMA and the relevant Minister will focus on their experience with the relevant property, how recent their interest in the title was, and their capacity to conduct the relevant decommissioning works.

However, it is important to note that the Trailing Liability Guidelines will be re-assessed in 12 months, and they do not limit the broad operation of the Act.

What’s the impact?

With increasingly mature assets and in a market environment where major oil companies are looking to sell down or out of their Australian portfolios, these changes make transactions directly or indirectly involving Australia’s offshore sector more complex. Practically, parties to any such transaction now need to engage early and proactively with the offshore regulators in addition to the Foreign Investment Review Board, the Australian Competition and Consumer Commission and others forming part of the Australian regulatory landscape, to ensure that transaction timetables can be met.

The wide-ranging change of control provisions will have significant implications not only for sale and purchase transactions involving titleholders as parties or as targets, but also their related parties higher up the chain of ownership. The absence of exceptions for securities market transactions (in Australia or elsewhere) as well as routine corporate restructuring activity such as rights issues and buy backs, will create additional regulatory burdens for the parties involved. The regime also adds complication for lenders exercising security and thereby ending up with a “controlling” stake in a titleholder, or for insolvency administrators – not parties accustomed to seeking the consent of NOPTA in order to exercise their contractual rights or statutory obligations, or to needing to meet financial and technical suitability tests.

The trailing liability regime operates as an impediment to clean exits by investors. The prospect of ongoing contingent liability (and uncertain tax treatment[ – see below]) may cause operators to cease production activity early, rather than selling out to smaller or lower cost operators. Alternatively, sellers may need to retain some involvement in or control over future operations and in particular decommissioning, so as to control the extent of their liability.

The contingent liability risk may discourage certain classes of potential buyer, such as fund trustees and private equity interest holders, where their structure exposes third parties to the risk of liability. Imposing financial assurance requirements to cover trailing liabilities post-sale, in circumstances where a remedial direction has been issued) may also be a deterrent to private equity buyers due to the potential long time horizons involved. Similarly, the enhanced technical and financial suitability requirements and ongoing compliance costs may deter certain classes of buyers.

Tax treatment

A further complicating factor of the new regime is that the tax treatment of decommissioning costs is not settled.

Under the current rules, decommissioning expenditure may be deductible for Petroleum Resources Rent Tax (PRRT) purposes. Such expenditure may also entitle a taxpayer to a refundable credit, if it constitutes “closing down expenditure” and exceeds assessable receipts (but not if production is continuing). Decommissioning costs may also be deductible for income tax purposes, although PRRT credits are assessable in that context.

It is unclear at this stage, how trailing liability concepts will interact with these tax rules, with the risk that the tax outcomes associated with decommissioning for called back former titleholders (or their related parties) will be different to those for current titleholders. For example, where a provider of financial assurance no longer has title, will they benefit from the PRRT and income tax deductions? These issues will need to be understood by industry, their advisors and the relevant authorities, in order for appropriate transaction structures to be developed that balance equitable tax treatment for industry and investors with clarity on funding of decommissioning liability.

What you need to do

• Assess the impact of the trailing liability provisions on your post 1 January 2021 portfolio. This should involve:

(a) where possible preparing (or requesting that the operator prepare) comprehensive decommissioning cost estimates for all your applicable assets and understanding when decommissioning is likely to commence;

(b) testing with the regulator whether alternative decommissioning solutions might be viable to reduce the costs involved. These could include (just by way of some examples) conversion to carbon capture, utilisation and storage projects, in situ disposal (sometimes known as rigs to reefs) or integration with offshore wind projects; and

(c) understanding (as well as is practicably possible) the creditworthiness of your counterparties and other historic titleholders who could potentially be subject to the claw-back regime with respect to your portfolio.

• Seek to introduce decommissioning security agreements (DSAs) into all your existing and future projects. DSAs were developed in markets like the UK which have had similar trailing liability regimes in place for many years, and are proven mechanisms for ensuring that no single party is left footing the entire bill for decommissioning costs and enabling a smooth continuation of trade in oil and gas assets. Although DSAs will be new to the Australian market, we have extensive experience with these documents garnered from our team’s international background and can help you get started.
• Consider your M&A strategy carefully. The treatment of decommissioning liabilities will become a core aspect of all Australian offshore oil and gas deals going forward. Remember that share deals will now attract the same level of regulatory scrutiny as asset deals. If selling, push for a bilateral DSA (known also as an M&A DSA) to ensure that the buyer and its successors in title sufficiently provision for decommissioning costs for the duration of the project. If buying, recognise that sellers who are keen to exit their Australian portfolios may be willing to retain some element of decommissioning liability in recognition that these new laws may make it more difficult for new market entrants to receive regulatory approval without this kind of assistance. Our experience overseas suggests that a broad spectrum of innovative transaction structures could evolve to deal with these changes to Australia’s oil and gas regime. 
• If you are a fund trustee or private equity investor considering investing in the Australian offshore oil and gas sector, and exposing your core fund or third parties to decommissioning liability is not possible, don’t fear. Although these changes make entry more complex, the regime is not all encompassing and a sufficiently ‘ring-fenced’ investment should be possible. However, very close consideration would be needed to appropriately structure your transactions.
• Before undertaking any corporate restructure, consider carefully the tests for a change of control and whether the notification and approval requirements under the Act will be triggered by the proposed restructure. As mentioned, the Act does not contain any exemption to the requirement to obtain NOPTA’s approval to a change of control of a registered titleholder which arises from a restructure of the corporate group for which the registered titleholder is part, even where the ultimate parent of the registered titleholder remains the same. If, for example, a parent entity proposed a corporate restructure which involved interposing a new entity into, or removing an existing entity from, the corporate chain of a registered titleholder, NOPTA’s approval of that change of control will need to be obtained before the restructure can be undertaken. 

Important Disclaimer: The material contained in this article is comment of a general nature only and is not and nor is it intended to be advice on any specific professional matter. In that the effectiveness or accuracy of any professional advice depends upon the particular circumstances of each case, neither the firm nor any individual author accepts any responsibility whatsoever for any acts or omissions resulting from reliance upon the content of any articles. Before acting on the basis of any material contained in this publication, we recommend that you consult your professional adviser. Liability limited by a scheme approved under Professional Standards Legislation (Australia-wide except in Tasmania).