Improving decommissioning accountability
Death and taxes
5.1
A significant issue facing all oil and gas producing facilities will be their eventual demise and decommissioning. This process, whether brought forward due to sudden changes because of climate change, or facilities reaching their natural end-of-life, has very significant risks not just for the operators but also for the taxpayer.
Extent of liability
5.2
The maintenance and decommissioning of structures, plant and equipment and wells and remediation of the environment can occur at any time in the life of a project to date, not just at the end of a project. Figure 5.1 shows the current maturity of Australia's oil and gas offshore industry. At this stage only a limited number of small decommissions have been completed, however, the number, size and complexity of such projects is expected to increase significantly from 2025.
5.3
Estimates of the extent of the decommissioning liability vary. In 2017 the then current offshore decommissioning liabilities were estimated at more than US$21 billion over the following 50 years and in 2020 it was estimated that the costs of on- and off-shore decommissioning over the next 30 years would be US$49 billion.
5.4
In March 2021 the Centre of Decommissioning Australia—part of National Energy Resources Australia (NERA), a not-for-profit company funded through federal, state and territory governments, industry and the science and research community—predicted that offshore decommissioning has an estimated liability of over US$40.5 billion ($55 billion) over 50 years with well plugging and abandonment, and pipeline removal comprising the majority of the spend. There are currently over 2 100 offshore oil and gas assets of varying size and complexity. Alternative modelling is also illustrated in Figure 5.2.
5.5
Assets in the North Carnarvon and Gippsland basins comprise 74 per cent of the decommissioning spend, with around 51 percent of the decommissioning liability expected to occur between 2020 and 2030.
5.6
By way of comparison the Oil and Gas Authority (UK) estimated that decommissioning the UK's oil and gas assets would incur costs of between £45 billion ($83.9 billion) and £77 billion ($143.5 billion), primarily over the next 20 years. However, it considered the estimates to be highly uncertain, but more certain over time as the industry learns from its decommissioning experience.
5.7
In the US recent estimated decommissioning costs for the total removal of all 3 000 offshore production facilities to be around US$38—$40 billion ($51.5–$54.1 billion), with costs increasing at roughly 10 percent per annum. In addition, the cost of plugging the 2.6 million onshore wells in the US is estimated to be US$280 billion ($379 billion), excluding costs for the estimated 1.2 million undocumented onshore wells. It has been suggested that US states have secured less than one percent of that amount in surety bonds, with a high risk that taxpayers will need to pick up the bill. Unconventional wells are anticipated to have even higher closure costs.
Australia's approach to decommissioning
5.8
Australia's onshore decommissioning regulatory framework is established by the laws of individual states and territories. Generally, onshore sites are required to submit an operations plan which includes decommissioning, abandonment, and rehabilitation plans, with the operations expected to regularly update and revise their plans as needed.
5.9
Australia's offshore decommissioning framework is comprised of environmental, safety, well integrity, and waste dumping provisions in various acts and regulations.
5.10
Specifically, the Offshore Petroleum Decommissioning Guideline—first released January 2018—outlined the decommissioning principles relating to:
environmental, safety and well integrity outcomes;
decommissioning responsibilities;
when decommissioning should be considered;
complete removal as the base case, though other options could be approved; and
decommissioning prior to block(s) becoming vacant acreage.
5.11
DISER commenced a review of the decommissioning framework in 2018.
Box 5.1: Case study: selling mature oil and gas fields
Selling mature oil and gas fields to late-life operators is likely to increase in Australian fields. For example, in 2019 ExxonMobil sought a buyer for all its Bass Strait oil and gas operations.
In 2016, Woodside Petroleum (and venture partner Talisman Energy) sold its mature Laminaria-Corallina venture in the Timor Sea to the Northern Oil and Gas Australia Pty Ltd (NOGA) group of companies. The deal included the Northern Endeavour production ship which was permanently moored at the oil field 550 kilometres north-west of Darwin. The price was not disclosed though speculation has suggested it was a 'peppercorn'.
Prior to the sale of late-life assets, the regulator, NOPSEMA, must be satisfied the buyer is capable of operating to the required standards and has sufficient bank-backed guarantees to cover the cost of field decommissioning and remediation. Media reported the regulator reviewed and approved the standing of the buyer.
The business model for late-life deals is companies like NOGA can make more money from a declining asset than a large company like Woodside because they carry fewer overheads. At the time of the sale, Woodside's projections suggested if the production rate was sustained, the project would generate sufficient cash flow to cover the cost of decommissioning, estimated at around $200 million. However, because the Northern Endeavour was not maintained to the standard required by NOPSEMA, production was unable to be maintained.
In January 2019, NOGA made a submission to DIIS' initial review into the offshore oil and gas decommissioning framework. In this submission it:
strongly opposed the government having the legislated ability to conduct assessments at any time of a titleholder's capacity to fulfil its obligations; and
opposed any requirement for industry to hold and demonstrate sufficient financial security to meet decommissioning costs.
On 18 July 2019, NOPSEMA suspended NOGA's production citing flaws in general systems maintenance, the fire protection systems, and corrosion management. It ordered immediate repairs estimated at around $50 million. This work was not done and NOGA placed itself and the ownership entity, Timor Sea Oil & Gas into voluntary administration. The administrator, KPMG, subsequently found the limited liability company that owned the remediation of Laminaria-Corallina was insolvent and could not meet its financial obligations.
The media reported NOGA went into administration, incapable of fulfilling the financial guarantees that it must have made to the regulator to enable the ownership transfer in 2016.
In February 2020 the federal government stepped in to ensure the safety and security of the Northern Endeavour and rehabilitation of the field. Decommissioning was forecast to take several years and government set aside $75.344 million over two years for the program, including nearly $9 million to Woodside for the provision of expert advice. The program was planned in phases:
Phase 1: decommissioning and disconnection of the facility from the subsea equipment
Phase 2: permanent plugging and abandonment of wells
Phase 3: removal of subsea infrastructure and remediation.
In July 2021 the government sought expressions of interest for Phase 1 and repairs and maintenance are being undertaken to prepare the facility for decommissioning.
Similarly, in 2016, Santos and Quadrant Energy sold the mature offshore Stag oil field in WA to a small and previously little-known company, Mitra Energy. Media reported the sale was US$10 million; one fifth of the original price it had agreed in 2015 with Malaysia's Sona Petroleum in a deal that subsequently fell through.
The field was acquired by Mitra's wholly owned subsidiary, Jadestone Energy (Australia) Pty Ltd and its application to operate the facility was accepted in December 2017, with a licence for drilling an additional production well approved in 2018. Infield drilling is expected to push the production life of the oilfield to 2024.
In mid-September 2020 Jadestone reported an oil spill at the facility, estimated to be between 151 and 1 288 litres of oil, although some estimates put the spill at closer to 10 000 litres. As a result of NOPSEMA's investigation the company was not fined but was issued with directions, including the conduct of an engineering and operational review of the hose connecting the stag platform to offtake vessel, a review of its oil spill response training, testing of oil spill arrangements, and training to ensure its workers are trained in oil spill response actions.
The Walker Review
5.12
While consultation on the decommissioning framework was underway, the Government initiated the Walker Review to investigate the matters leading to the administration and liquidation of the NOGA group of companies and the abandonment of the Northern Endeavour floating production storage and offtake facility.
5.13
The Government sought to understand how this occurred and to consider how best to minimise risks of a similar event reoccurring. Mr Steve Walker, a UK-based expert with offshore regulation and industry experience, was appointed to head the review.
5.14
The review examined the roles, responsibilities, and behaviours of the key stakeholders, including the NOGA group of companies, NOPSEMA, NOPTA and the Joint Authorities; and advised on potential reforms of the offshore oil and gas regulatory regime.
NOGA's financing, experience and reliance on a single asset as its only income source, presented challenges;
NOPSEMA took a strategic approach to managing environmental and safety concerns for the Northern Endeavour; and
NOPTA acted appropriately but that legislative limitations prevented it from acting on its concerns.
5.16
The review made nine recommendations to improve practices, policies and legislation; and the government committed to keeping the facility and surrounding environment safe pending a longer-term solution.
5.17
The department's decommissioning policy review and the Walker Review both identified the need for more transparency and government oversight for commercial transactions resulting in changes to ownership and/or control of a titleholder entity through a corporate merger, acquisition or takeover. The Walker Review observed that the limited application of trailing liability was inconsistent with comparable jurisdictions managing a mature industry and both reviews identified the need to enhance trailing liability provisions to protect the interests of the broader community and taxpayers.
Regulatory activity
5.18
Subsequently, and as a result of ageing oil and gas facilities and the abandonment of the Northern Endeavour the government stepped up its focus on decommissioning and associated compliance.
5.19
In 2019 the Minister for Resources and Northern Australia issued a statement of expectations to NOPSEMA, highlighting the need for an increased focus on decommissioning.
5.20
Importantly, for any future projects NOPSEMA will be focussed on operators' plans for decommissioning from the very early states of a project, and they will expect decommissioning to be addressed in all permissioning documents.
5.21
The regulator is aware of increasing pressures on operators to reduce costs, especially when field production declines, but warned operators of their legal duties to maintain infrastructure and address issues such as corrosion and other structural damage.
5.22
In late 2020 the Hon Keith Pitt, MP, wrote to the Chair of ExxonMobil to clarify the Australian Government's ongoing expectations for the management of Gippsland Basin assets and potential sale, noting that the new owner/operator should have the appropriate financial and technical capacity and capabilities and that the government intended to hold ExxonMobil liable for any trailing liabilities. ExxonMobil subsequently stopped its reported sale to Beach Energy and exit from the Bass Strait.
5.23
Subsequently, in April 2021 NOPSEMA published its five-year Decommissioning Compliance Strategy and Plan to help operators understand its requirements for planning and implementing decommissioning work and related compliance actions. NOPSEMA told industry that:
Our goal is to have decommissioning plans in place by 2023 for all facilities where property and equipment is no longer in use, and by 2025, property and equipment should be removed within five years of not being used and wells permanently abandoned within three years of ceasing production.
5.24
The long-standing legal requirement to remove all structures, equipment and property remains. However, equipment floating in the ocean must be removed within 12 months of a permanent end of operations, all wells are now required to be plugged and abandoned within three years of the end of production and the seabed cleared within two years after that. The requirements of the new decommissioning compliance strategy are intended to force operators to decommission sooner given the higher risks associated with delays.
5.25
NOPSEMA has also started to issue time-limited directions to operators. In May 2021 NOPSEMA ordered ExxonMobil and its partner BHP to plug and abandon 180 wells and dismantle 10 platforms in the Bass Strait by September 2027. ExxonMobil is also required to fix dangerous corrosion on two platforms.
5.26
NOPTA outlined the increasing engagement that occurs with operators as they enter the decommissioning phase, and NOPTA's interest in ensuring long-term optimum recovery from a field and avoiding the risk of 'premature decommissioning', where significant reserves are left in the field.
Industry approaches to decommissioning
5.27
APPEA described the closing down and rehabilitation phases of a project, which can take place over two to 10 years. It characterised this phase as having increasing closure costs and lower revenues for operators.
5.28
While the default position of the regulator is for the full removal of infrastructure at the decommissioning phase of oil and gas projects other jurisdictions, such as the US, have allowed leave in place options. Since the 1980s the Rigs-to Reefs program, with over 532 offshore platforms (11 per cent of platforms decommissioned) has seen the re-purposing of platforms in the Gulf of Mexico. Mr Walker told the committee:
… in the US, they've gone to what I think they call a rigs-to-reefs initiative, whereby they did specifically leave some of the infrastructure, some of the pipeline et cetera, in order to provide artificial improvements to the environment for fish and stuff like that. So it would be good if you did have that flexibility [in the Australian legislation], in my opinion.
5.29
Van Elden, Meeuwig, Hobbs and Hemmi have pointed to increasing evidence of the important ecosystems and refuges that that offshore oil and gas platforms can provide–
The successes of various Rigs-to-Reefs projects, particularly in the Gulf of Mexico, have demonstrated that these structures can be effectively repurposed as artificial reefs … However, to date only a few countries around the world have successfully implemented Rigs-to-Reefs programs…
5.30
However, researchers noted that just because Rigs-to-Reefs has been successful elsewhere:
…it does not mean it would automatically be an ecologically beneficial exercise in … Australia … [and that] … creating a reef, simply because there is a platform that needs to be decommissioned, is indeed little more than waste disposal.
5.31
Nevertheless, researchers cited the potential value of these man-made ecosystems and the fact that these programs are not automatically environmentally detrimental.
5.32
Senator Slade Brockman told the committee that he had been advised that the decommissioning framework is 'overly prescriptive' in some respects and that it prevents companies following international industry best practice when decommissioning, for example by allowing decommissioning in place.
5.33
Senator Ben Small told the Senate that adopting leave in place options would save $9 billion on the overall decommissioning liability and would provide natural habitats for fish stocks and recreation use. He noted that the cost of decommissioning to the taxpayer through legitimate taxation relief—due to deductions against both company income tax and the PRRT—could be as much as $17.8 billion over the next 10 years.
5.34
In February 2021 NOPSEMA issued deadlines for the clean-up of the Enfield oil field in WA. Woodside had planned to tow equipment to shore to be dismantled but lack of maintenance made this impossible. Woodside then planned to leave the infrastructure in place, creating an artificial reef, and setting a precedent for the decommissioning of other facilities. However, environmental risks posed by 65 cubic metres of polyurethane foam inside the riser turret mooring scuppered these plans. As of October 2021, NOPSEMA were investigating possible breaches of the law relating to lack of maintenance.
Maximising decommissioning accountability
Decommissioning financial security
5.35
The committee heard from submitters that they are concerned that some oil and gas companies have attempted to forego decommissioning liabilities through the sale of late-life assets to smaller operators, lack of appropriate maintenance and pursuing leave in place decommissioning options—leaving taxpayers to foot the bill. Dr Cameron Murray said:
I would add a little bit of a political consideration into that. If you think about coalmines and other sorts of things across the states, you do find that private entities are very good at disappearing or dissolving before they meet any of these liabilities, which is why, for example, states implement remediation levies upfront to ensure that these companies don't disintegrate and disappear before spending the money on their remediation obligations. So, in some ways, I already see that risk as a public risk, held by the public, to a degree.
5.36
Senator Larissa Waters also advocated for a long-term levy to reduce the impact on taxpayers:
We're in this mess because Woodside offloaded an old rig, the Northern Endeavour, to a fly-by-nighter—who went bankrupt within a very short time of acquiring the assets—so Woodside could conveniently avoid the decommissioning costs. Woodside has privatised the profits and socialised the losses, as so often happens in the mining industry. Any sense of justice says that they should pay the full costs, but a long-term levy on the industry for decommissioning is the next best solution.
5.37
The Australia Institute strongly supported financial provisioning for decommissioning costs, as did Prosper Australia, with the latter suggesting environmental bonds for this purpose, potentially on a sliding scale, with an increase in bonds according to the carbon budget.
5.38
However, Herbert Smith Freehills, in their 2019 submission to the decommissioning framework consultation argued against requiring titleholders to provide security, as has been the case in the UK. It argued that a blanket requirement may stifle investment, add unnecessary costs or exclude participation. Moreover, at the time of writing it noted there was no offshore facility where decommissioning works had not been completed due to lack of funds, and that, by implication, a security arrangement is unnecessary.
5.39
As an alternative, Dr Prafula Pearce of Curtin Law School suggested that the Australian Government require decommissioning insurance to be in place until all structures are decommissioned to the satisfaction of the regulator and considering long term liabilities that may be incurred after the end of operations.
Enhanced framework for decommissioning
5.40
In December 2020 the department released an enhanced framework for public consultation, as outlined below, followed by an exposure draft of the Offshore Petroleum and Greenhouse Gas Storage Amendment (Titles Administration and Other Measures) Bill 2021 and Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Amendment Bill 2021.
5.41
The committee heard evidence from a number of submitters, generally in support of the strengthening of Australia's decommissioning regime.
5.42
A number of the changes suggested by witnesses were incorporated into the enhanced decommissioning framework, endorsed by the Australian Government in April 2021.
5.43
In August 2021 Parliament passed the Offshore Petroleum and Greenhouse Gas Storage Amendment (Titles Administration and Other Measures) Bill 2021 and Offshore Petroleum and Greenhouse Gas Storage (Regulatory Levies) Amendment Bill 2021, giving effect to the enhanced framework. Most of the reforms come into effect on 2 March 2022.
5.44
Draft guidelines and factsheets were issued on 25 October 2021 for public consultation The framework is expected to be fully implemented by the second quarter of 2022.
5.45
The enhanced framework adopts some of the recommendations from the Walker Review, and makes enhancements in the areas of financial oversight, planning and management, and accounting and trailing liability.
5.46
Key elements of the enhanced framework include:
strengthening existing trailing liability provisions;
increased oversight of changes in company control;
increased requirements for assessment of suitability to operate including regular financial assurance and technical capabilities, as well as historical compliance and corporate governance matters at particular decision-making points;
modernising field development plans and enhancing planning;
earlier and proactive use of monitoring and remedial directions powers;
improved transparency and public engagement and reporting;
increased information gathering powers for NOPTA; and
other minor and technical amendments.
5.47
The enhanced decommissioning framework makes provision for financial security:
The department also expects forms of financial assurance, such as bonds and securities will be used under the enhanced framework. Where these tangible forms of assurance are required by NOPSEMA, these forms of financial assurance should be accessible by government or a third party endorsed by government in the event that decommissioning activities are not undertaken. This is consistent with the Walker Review.
…
International and domestic experience shows that governments expect stronger guarantees that a company can meet the expenses and liabilities associated with undertaking petroleum activities. This includes decommissioning liabilities and being a safe and responsible titleholder.
5.48
The framework acknowledged that an insurance policy may not be an acceptable form of assurance if a company cannot demonstrate that the policy will continue to be in force (for example, if the company goes into administration).
Offshore oil and gas levy
5.49
The PC's 2020 review of resources sector regulation found that:
Surety arrangements for rehabilitation generally have been inadequate, but are being strengthened. Bonds that cover the full cost of providing rehabilitation offer the highest level of financial assurance for governments, and provide companies with full incentives to complete rehabilitation in a timely way. Surety requirements should be adjusted to reflect and encourage progressive rehabilitation. Jurisdictions are heading in this direction, but a leading practice jurisdiction has not been identified.
5.50
It also noted that having financial assurance arrangements in place provides incentives for companies to meet their obligations and reduces the risk of costs being borne by the government, and hence taxpayers.
5.51
As part of the development of the enhanced decommissioning framework DISER told the committee that 'where similar offshore renewable energy frameworks are being developed internationally, it is common for security, such as a bond, to be required prior to construction commencing'.
5.52
While the government's enhanced decommissioning framework requires financial assurance it does not require security. Nevertheless, on 11 May 2021 the government announced that it would impose a temporary levy on all offshore petroleum production to recover costs of decommissioning the Northern Endeavour and associated infrastructure and remediate the Laminaria-Corallina oil fields. The estimated cost of remediation is between $200 million and $1 billion. The levy is estimated to raise approximately $367 million per year and will ensure taxpayers do not have to cover costs.
5.53
Treasury conducted public consultation on the exposure bill, although feedback has not been made publicly available. DISER also conducted consultation in relation to the levy and its operation.
5.54
The bill to effect the levy—the Offshore Petroleum (Laminaria and Corallina Decommissioning Cost Recovery Levy) Bill 2021—was introduced into Parliament on 20 October 2021 and referred to this committee for inquiry. The committee reported on 18 November 2021 and its report is available on the committee website.
5.55
The levy applies at a rate of 48 cents per barrel of oil equivalent produced, based on the annual physical production at the wellhead (not production) from 1 July 2021 and will be levied annually in arrears with the first payment due the first half of 2022–23.
5.56
The levy will remain in place until all costs are covered up until the financial year commencing 1 July 2029, with a mechanisms to terminate the levy early or lower the levy to prevent 'over-collection' by the Government. The levy will not be deductible for any other form of Commonwealth taxation, including company tax, PRRT, the North West Shelf royalty or crude oil excise.
5.57
350.org Australia welcomed the application of the temporary levy and recommended that a permanent levy be implemented to cover decommissioning costs and reduce public risk:
… it is only temporary and is being heavily fought by the petroleum industry and lobby groups, who have called the minor, 1% per barrel, or 48 cent levy 'extreme' and it seems it would prefer to see the public bear the costs of cleaning up after the oil and gas industry. A permanent levy is needed or an overhaul of the legislative framework is needed to ensure that clean-up costs are carried by the companies who have profited from infrastructure.
5.58
The oil and gas industry have labelled the levy as 'over the top and extreme' and are unhappy that the levy has been applied to all offshore production, not just Woodside, and have suggested that the government consider other options including alternative cost recovery measures.