Shareholders request that the Board disclose annually from 2023:
A list of all onshore and offshore oil and gas infrastructure which may be decommissioned over the medium-term;
Audited asset-level provisions for the decommissioning of this infrastructure and restoration of sites, along with the major assumptions underpinning these provisions;
Analysis of the useful life of all assets using different oil and gas demand scenarios, including the IEA Net Zero by 2050 scenario.
Nothing in this resolution should be read as limiting the Board’s discretion to take decisions in the best interests of our company.
As Australia's oil and gas industry matures, decommissioning liabilities are increasing. In 2020, Wood Mackenzie estimated the current cost of Australia's onshore and offshore decommissioning at more than US$49 billion (A$60 billion) over the next 30 years. For the offshore oil and gas industry alone, decommissioning over the next 50 years has been estimated at USD$40.5 billion ($56 billion), with 51% of activities likely to occur before 2030.
Australia’s national offshore regulator, NOPSEMA, warns the task ahead is significant - expensive, complex, and high-risk. As decommissioning is in its infancy in Australia, high-level cost estimates have not been reconciled to actual costs. Internationally, remediation costs have often exceeded provisions. In a 2021 North Sea study, the average actual cost was 76% more than estimated. NOPSEMA is concerned that industry is not valuing assets on the basis of full removal, and at times failing to facilitate full removal due to improper maintenance.
Scrutiny around our company's decommissioning activities has increased since the Northern Endeavour case. The subsequent Walker Review highlighted our company’s decision to sell an ageing asset, leaving a “legacy” of “extensive corrosion” as well as several outstanding regulatory matters. The case has elevated political and media critique of our company, and attracted inter-industry critique.
In this context, new federal legislation has been passed. Operators are facing strengthened trailing liability provisions; increased oversight of company control; stricter financial assurance requirements; strengthened remedial directions powers; and new transparency measures. A non-deductible levy, estimated by APPEA to generate up to $3.4 billion (~USD 2.4 billion), must now be paid by all producers. As Woodside and BHP produce almost 20% of Australia’s oil and gas, our merged company's levy may be more than USD$400 million.
Simultaneously, regulatory pressure is increasing. NOPSEMA has warned that “some titleholders (are) not develop(ing) appropriate decommissioning plans in a timely manner, potentially increasing risk exposure”, and has introduced a suite of new policies. NOPSEMA has asserted that ageing asset management and life extension risk must be managed proactively, and at a senior level. New regulatory timelines stipulate that from 2025, all structures, equipment and property must be completely removed within five years. NOPSEMA is now issuing more directions, prohibition notices and improvement notices, including to our company, and has stressed its willingness to prosecute maintenance failures.
Company decommissioning provisions are calculated using information about assets (age, condition, complexity), and assumptions about removal requirements and future costs. These assumptions are moderated by legislation (climate, environment, safety, taxation), regulatory settings, and oil prices, among other factors. Consequently, decommissioning is increasingly viewed as relevant to climate risk reporting.
Company provisions for decommissioning
Our company discloses group-level provisions for “restoration of operating locations” drawing upon a range of “judgemental assumptions” relating to timing, engineering, technology and “liability-specific discount rates”.
In our company’s latest Annual Report, this restoration provision was USD$2.134 billion. This is a material fraction of our company’s value, which is likely to increase substantially if the merger with BHP is approved.
Values Woodside BHP Petroleum Merged entity
Market Cap (USD bn @ 9 February 2022, assuming 52:48 valuation of BHP Petroleum) 18.3 16.9 35.3
Restoration Provision (USD bn) 2.1 3.9 5.78
The only assumptions specifically disclosed in the latest Annual Report are the discount rate (0.1-2.0%) and that 73% of the provision is not expected to be settled within 10 years.
Considering the 2021 North Sea study found decommissioning provisions were underestimated by an average of 76% (range 21-189%), greater transparency on the major assumptions informing these liabilities is a modest request from shareholders.
Current and future decommissioning works
Existing ad-hoc disclosures and regulator information provide limited insight to our company’s decommissioning portfolio.
Under the Offshore Petroleum and Greenhouse Gas Storage Act 2006, our company has been ordered to:
Nganhurra FPSO (production ceased 2018), WA: plug and abandon 18 wells and remove equipment by 2024. Failure to preserve a riser turret mooring (RTM) has resulted in an Environmental Improvement notice and limited disposal options. The decommissioning strategy now appears uncertain since a proposal to turn it into an artificial reef was withdrawn.
Stybarrow FPSO (production ceased 2015), WA: plug and abandon 17 wells and remove all subsea equipment by 2025.
Our company has also received NOPSEMA approval for its plans to decommission Balnaves, Echo Yodel and Capella in Western Australia. Plans to decommission Eaglehawk, Thebe-1, and Calthorpe-1 (WA) wellheads are still being assessed.
In addition, NOPSEMA has issued two General Directions to BHP in 2021 for the Minerva Gas Field in Victoria (for completion 2025) and the Griffin FPSO in WA (for completion 2024).
With regard to operating assets, our company does not disclose cessation of production (CoP) dates for its current assets. In the absence of CoP data, reserves and production data allow an estimate of remaining production at current rates:
Australia Oil (Two FPSOs Nguyjima-Yin and Okha): 3 years
NWS (North Rankin, Goodwyn and Angel platforms, five LNG trains): 6 years; consistent with the first LNG trains being decommissioned from 2024.
Pluto (Pluto A and Pluto LNG): 9 years, noting that Scarborough is intended to backfill the Pluto plant.
Wheatstone (Two LNG trains, and associated offshore infrastructure): 14 years
Decommissioning is an evolving, material issue that intersects with a broad range of risk areas, including financial, regulatory, safety, environmental and climate change. These escalating risks call for improvements to company disclosures.
ACCR urges shareholders to vote for this proposal.
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