There is no such thing as a colossus with clay feet in offshore petroleum exploration and production (E&P). Most rigs have been tethered to the seabed with tons of concrete, grout and steel piles. Since the 1970s, we have continuously indulged our fossil fuel addiction with Brent oil, somewhat careless of the cleaning job to come. But over the next 30 years, virtually all the infrastructure put in place in the North Sea will require decommissioning, representing an enormous engineering challenge. Tons of scrap iron will have to be broken down in large quantities, calling for a well-honed supply chain and the development of a competitive industrial capability.
Decommissioning has clearly become one the main issues facing the global offshore oil and gas industry. It’s expected that 15 to 25 installations will be decommissioned annually in Europe during the next 15 years. For the UKCS alone, this amounts to the dismantlement and removal of the approximate equivalent of 254 Eiffel Towers - 31 of them weighing in fact a lot more (i.e. more than 10,000 tonnes), eight installations with large concrete substructures (in the region of 20,000 tonnes), 280 subsea and 21 floating production systems and last but not least, 3000 pipelines and 5000 wells.
Beyond the technical and logistical challenge, removing ageing E&P infrastructure from the seabed in a safe and effective way entails huge expenditures. A large number of fixed offshore structures were not designed to be removed. Norway, for example, accounts for 35 percent of the estimated worldwide decommissioning expenditure, with only 7 percent of the global offshore infrastructure. The choice of heavy concrete gravity-based rigs as a way to withstand harsh climatic conditions off the Norwegian coast largely explains this significant cost discrepancy.
Dealing with such large structures compounds the difficulty. But so does pushing the E&P frontiers to higher depths. Deepwater offshore drilling is becoming increasingly common around the globe, imposing seasonal adjustments on an already long dismantlement cycle. Weather conditions are too erratic during winter months for lifting large structures and removals tend to occur mainly throughout the summer months. In Brazil, 50 percent of offshore platforms are installed in depths greater than 400m, and the country still retains the record for deepwater completion at the Perdido field, currently the world's deepest producing offshore project (2,438 meters of water).
Well-plugging and abandonment (P&A) will add up to the global expenditure by constituting two of the most expensive activities within any decommissioning process, not to mention the technical complexity and the time involved in doing so. Data from the Shell oil company suggests that the P&A costs on Brent Delta are £2.7 million per well, each taking on average 30 days to complete.
The cumulative expenditure for decommissioning the UK sector of the North Sea alone may be above £35 billion over the next 30 years, with a lot of uncertainty still surrounding the estimates being made. Decommissioning costs remain notoriously difficult to pin down, but economic modeling suggests that higher oil prices enable operators to spread them more evenly, although at a higher overall global cost.
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One central concern for the industry relates to the timing of such expenses and the fact that they occur precisely when production has ceased, hence resulting in a stream of negative cash flows. From the companies’ point of view, this represents huge incremental costs over the life of the field. More than half of those will be incurred by governments through tax relief schemes, whereby - quite ironically - taxpayers become the main shareholders in a business most are hardly aware of.
Offshore E&P tends to exacerbate environmental concerns, and it is no mystery that the Deepwater Horizon accident is still simmering on the back burner of the public’s consciousness. As a result, even the most strictly law-compliant oil companies may be miles away from satisfying public expectations, no matter how close they adhere to the legal frameworks. Despite approval from the British government, Shell provoked widespread outrage in 1995 when the company announced its intent to abandon his ageing floating storage Brent Spar facility off the coast of Scotland.
The environmental uproar that followed helped move the lines of regulation, but not necessarily in the right direction. With the OSPAR agreement, a group of European countries agreed that the future disposal of oil facilities would be handled onshore, unless impossible. While the conversion of abandoned offshore rigs into artificial reefs - known as rig-to-reef programs - is largely accepted in regions like California or the Gulf of Mexico, deepwater disposal of larger structures off the continental shelf is no longer permitted in Europe; at least, under the current legislation.
Nevertheless, a number of oil rigs will still benefit from a derogatory regime due to the physical impossibility of a safe and cost-efficient dismantlement. This suggests, if anything, that increased flexibility or at least, regulation on a case-by-case basis might be more appropriate. The lack of homogeneity between regulatory frameworks across the 53 countries involved in offshore E&P brings even more strength to the argument. Excessive rigidity may gradually shoo potential investors away from declining petroleum provinces like the North Sea, and policy makers are increasingly realizing the benefits of more flexibility to their regulations.
It is commonly believed that ageing offshore assets are more vulnerable to unplanned shutdowns, which may partly explain the major loss of production efficiency throughout the UKCS: from 81 percent to 60 percent between 2004 and 2012. Although a recent study has not found any clear evidence of this, rigs nearing retirement are yet exposed to longer and more frequent downtimes (due to corrosion problems, leaks…etc.). And the problem can easily spread to adjoining fields due to the high degree of interconnectedness between facilities.
Although this is a well-known characteristic of the oil and gas industry, it remains a relatively new problem to most offshore operators. A number of oil rigs commissioned throughout the 1970s are now approaching the end of their economic life, a lot of them at the same time. Therefore, governments face a thorny dilemma. On the one hand, they want to avoid unwanted liabilities such as possible environmental damages arising from badly managed licenses, which -- in the end -- would accrue to the taxpayer.
On the other hand, they must not deter entry of smaller operators, lest fields be abandoned earlier, resulting in a loss of tax revenues. There is growing concern over the decline of the North Sea as a petroleum province and the fact that decommissioning schemes should be designed, whenever possible, to maximize the basin’s life or at least, not to shorten it. Tight regulatory frameworks may create fiscal distortions and increase the risk of early abandonment, hence representing a serious impediment to assets trading and the maximization of the UKCS. By this token, the Wood Report has emphasized the importance of schemes like enhanced oil recovery or marginal field development.
The exploitation of depleted sites may become unviable for large capital-rationed oil companies, which are likely to set their investments alongside competing opportunities elsewhere. Inversely, it might become attractive to companies with smaller costs and more expertise in EOR or marginal field development. Moreover, the materiality of their returns, however modest, might be much larger to their shareholders. Despite the Wood Report’s recommendations, the current combination of a tight regulatory framework with a high tax take seems to defeat the purpose of good production efficiency stewardship.
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In a deliberate attempt to extend field life and maximize economics returns in the North Sea, a significant number of offshore assets have been transferred from large to smaller oil companies in recent years. Unfortunately, those new entrants are often perceived as the potential bearers of a greater risk of insolvency. And this is a problem with regard to decommissioning. Under the UK Petroleum Act 1998, there is joint and several liability among licenses, which means that both past and present license holders are liable for decommissioning expenditure. If a new owner defaults, liability transfers back to the original license holder.
As a result, sellers and governments commonly require strong financial guarantees to avoid a bankruptcy scenario. This compels smaller potential buyers into using various financial instruments (Letters of Credit, security bonds, escrow accounts), putting an additional constraint upon their cash availability for other developments. In the meantime, it also places higher hurdle rates onto their path to profitable development with marginal fields. For this reason, the government should be concerned about balancing a rigid regulatory framework with adequate incentives to facilitate the transferability of leases.
In the light of the Wood Report, the continuing and successful exploitation of depleted plays by smaller companies should be encouraged. Strong incentives such as tax deductibility should therefore not be ruled out as a way to incite smaller operators to provide such guarantee funds. Current requirements on licensees may be overly prescriptive, but the possibility of tax deductibility will be key to avoiding strangled asset trading. From the government’s point of view, the cost of such fiscal schemes should not only include the direct costs of tax reliefs, but also the amount of forfeited tax revenue if decommissioning occurs earlier as a result of lower asset divestment.
The petroleum industry is characterized by a specific cash flow profile. The net present value (NPV) of projects becomes negative when decommissioning expenditure is incurred at the end of a field’s commercial life. Companies can therefore no longer obtain deductions against taxable income.
Most countries are rather shy on giving permission to tax deductions ex ante (based on future expenditures) because this may reduce or eliminate industry compliance with their ex post decommissioning obligations. A company susceptible to obtain its allocated decommissioning capital through tax deduction before the end of the project might have little incentive to comply afterwards. It may also indulge its opportunistic penchants and overestimate future decommissioning expenditure and hence obtain higher upfront benefits.
Governments have to strike the right balance between avoiding foregone tax revenue – due to early abandonment - and the risk of passing the decommissioning liability onto the taxpayers if the regulatory framework becomes too loose. Although there is probably no silver bullet to the joint problem of decommissioning, strangled asset trading and maximizing the UKCS, the ability to obtain deductions against taxable income is germane to the set up of adequate incentives, in particular to make sure that the amount of oil and gas left in the ground is kept to a minimum.
By Julien Mathonniere