Energy companies must manage huge uncertainties. These include making provisions for decommissioning costs on major assets such as power stations and oil and gas rigs that may operate for 20, 30 or perhaps even 50 years into the future.
Actual decommissioning costs are subject to a range of different variables, including the cost of equipment and labour, changes in environmental regulations and the future impact of climate change. There is also doubt over assets’ likely end-of-life date, which will change according to technological developments and future wholesale energy prices.
Jimmy Daboo, a KPMG energy audit partner, explains: “There are multiple variations which can produce different outcomes. When you start to provision you are potentially decades before decommissioning actually happens. Accounting people are in the business of making estimates all the time. Usually these are for a shorter term period and with less variables.
“Essentially it is a matter of engineering. Then it is a matter of costing those engineering outcomes. Then you take into account the time value of money. Then you factor in something which takes into account the risk.” In other words, the provisions are basically calculated according to what the cost would be today, add 20% or so as a premium to cover the risk of things going wrong and use a discount rate to reflect the future value of money.
Jamie Drummond, a PwC director for assurance, warns: “A significant uncertainty is the scope of the work itself, particularly with old oil and gas platforms. For many companies, getting precise and complete information about the original construction is a challenge. Many installations date back to the 70s and 80s, since when they may have been subject to M&A activities, personnel changes, and ongoing redevelopment, so the inventory of what needs to be taken out on abandonment is not always clear.
“The relevant legal and regulatory frameworks can change over time too, often in response to environmental concerns, affecting what may or may not be left on the sea bed at the end of the field’s production life. Some E&P companies communicate their own standards, which may be in excess of the legal obligations and the basis for their provisions should be consistent with their own requirements.
“Under the accounting standards, the provisions have to take account of risk, for example, weather risk, unexpected complications, the discovery of environmental issues while the work is underway. There is a lot of investment currently going into decommissioning R&D, but the accounting standards don’t allow the calculation to assume improved technology in the future. You can only provision for proven technology.
“However, it may be possible to assume efficiencies, for example, where there are cost benefits from planning to decommission a wider area of connected facilities at the same time, as opposed to costing the work at an individual asset level in isolation.”
Another complication is working out the likely date when production will cease. This will vary according to any improvements in extraction technologies and also the wholesale energy prices as the end-of-life nears. This affects what is called the CoP or Cessation of Production date. “That has to be re-assessed every year,” says Drummond.
Kevin Weston is an EY assurance partner and an energy market lead for the firm. He reports that his clients have teams constantly working on updating costs and improving efficiencies. With some rigs and platforms built in the 1970s now being decommissioned, provisions can increasingly be based on experience. “This gives them a datapoint,” he explains.
Experience of decommissioning generates what Weston terms “economies of efficiency and learning”, with many rigs and wells being similar in terms of design and location. “A lot of companies are looking at technology – for example, drones that look around the rig to do the surveys, and using analytic and robotic processes,” he adds.
Operators in Europe’s North Sea have been dealing with an additional challenge over the last year. “Costs have been in pound sterling, but they report in US dollars,” says Weston. For those companies, the fall in the value of the pound affects dollar-based provisioning estimates.
Risk is one of the big concerns, with the possibility of many things going wrong during decommissioning. In some instances energy majors have offloaded near end-of-life assets to smaller energy companies that specialise in operating assets at lower volumes over a longer period. Those end-of-life operators will then take responsibility for decommissioning. In other instances, an energy company will pay a specialist decommissioning company to take over the liability.
Decommissioning liabilities feature as serious considerations during M&A negotiations. In some cases this has involved the seller underwriting decommissioning costs, or retaining decommissioning liabilities. Oil and gas extraction facilities are often owned by joint ventures, with all partners jointly responsible for decommissioning liabilities. Each partner must then continually monitor other partners’ financial capacity to meet their decommissioning liabilities.
Corporations also have to do tax planning for the decommissioning. Mairi Massey, a PwC tax director, explains: “You don’t get any tax relief from the provisions, only when paying the actual costs incurred.” Until then, an element of the expected costs can be accounted for as a deferred tax asset. But the value of the potential tax relief is based on tax rates applicable during the life of the asset – a complex calculation given that these rates may have changed several times.
Decommissioning arrangements vary according to location. In some African and Asian countries, operators pay government an annual charge to meet future decommissioning liabilities – with the government taking over responsibility. The end result is similar, whether states provide tax relief to assist with costs, or take direct responsible for the decommissioning. KPMG’s Daboo comments: “One way or another, the government underwrites the process.”