Who makes decisions about the development of Australia’s offshore oil & gas resources, and who pays to decommission end-of-life assets, have been high on the news agenda since the owner of the Northern Endeavour FPSO went into liquidation in February 2020.
The Commonwealth’s response to the Walker Review of offshore regulation in the aftermath of the Northern Endeavour situation has included extensive amendments to the key legislation governing Australia’s offshore assets, including the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (Cth) (the Act).
The Offshore Petroleum and Greenhouse Gas Storage Amendment (Titles Administration and Other Measures) Act 2021 (Cth) containing those amendments has now been passed by Parliament and received Royal Assent on 2 September 2021.
Certain information gathering powers commenced from 2 September 2021, with Royal Assent, with the remaining amendments expected to commence from 3 March 2022. The trailing liability provisions will have retrospective effect from 1 January 2021.
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:
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.
However, the amendments are an incomplete package. Guidelines and subordinate legislation in relation to key areas are yet to be drafted, including in relation to taxation, as is related legislation to impose a temporary levy on offshore petroleum production to recover the cost of decommissioning the Laminaria-Corallina oilfields and associated infrastructure (currently under the federal government’s control following the liquidation of Northern Oil & Gas Australia).
A brief overview of the substance of the changes follows, together with comment on their impact.
The approval of NOPTA (the National Offshore Petroleum Titles Administrator) will be 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 – will require NOPTA approval.
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.
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.
While the Explanatory Memorandum notes 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. Industry and other interested parties will need to look to NOPSEMA guidance – if and when provided – to determine the regulator’s approach.
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 will make transactions directly or indirectly involving Australia’s offshore sector more complex. Practically, parties to any such transaction will 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.
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.
In other jurisdictions – notably the UK North Sea – late life offshore assets have been attractive to smaller oil & gas companies, whether publicly listed or backed by private equity, as well as to operators focused on using new technologies to increase recovery from mature assets. The trailing liability concept as implemented in the Act bears some similarity to the equivalent UK regime, where the costs associated with mature North Sea assets and the regulator’s powers to impose liability on a wide range of parties for decommissioning costs acted as an impediment to M&A activity.
The UK government and industry have over time arrived at mechanisms to address decommissioning liability by way of decommissioning security agreements (DSAs), whereby transacting parties put funds into a trust which are available to pay for decommissioning costs at the end of the asset’s life. DSAs can be between a buyer and a seller only, or on a field-wide basis between all joint venture parties over time. Tax relief is available to parties transacting with their interests to enable buyers to obtain the benefit of some of the seller’s tax history. Field-wide DSAs, in particular, avoid multiple layers of security being provided by different parties over time in respect of the same cost to each other and potentially to the regulator, tying up capital and limiting entry by smaller parties buying from larger sellers without the resources to take over their existing security.
A shared, industry-standard approach to decommissioning costs has provided a degree of certainty for transacting parties that they will not be “on the hook” to a disproportionate extent, as well as certainty for the regulator that the cost burden will not fall on the tax payer. In parallel with the emergence of the DSA model, has come the recognition that “clean-break” exits from mature UK North Sea assets are no longer feasible and new M&A structures have developed as a result involving sellers retaining a degree of control or involvement over the sold interest, either throughout its remaining production life or from the point at which decommissioning begins.
DSA-type structures may provide one possible solution to trailing liability in an Australian context. However, any decommissioning fund created as a trust would at a minimum need to be creditor-remote and give priority over lender security by statute (or transaction specific priority agreements), to be effective.
NOPTA and NOPSEMA are expected to issue guidance on the new regime in advance of these changes to the Act coming into force in March 2022. The issues touched on in this article will need to be considered for any transaction involving a target in some way connected to Australia’s offshore sector, as well as by existing industry participants. Transacting parties in Australia and elsewhere, will need to allow for additional time and, and consider carefully what engagement is required with NOPTA. Similarly, unless and until industry-wide approaches to managing decommissioning risks and costs emerge, including by way of more extensive decommissioning provisions in joint operating agreements and other joint venture agreements, sellers and buyers will need to contractually manage trailing liability risks as between themselves.
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