The UK’s offshore oil and gas industry has undergone a torrid few years, starting even before the oil price crash of 2014. The industry has of course been here before and has demonstrated itself to be adaptable and resilient. In 2014, with oil prices which had averaged over $100 for several years, production was 1.4 million barrels of oil equivalent (boe) a day, down from a peak of almost 3 million boe a day in 1999, while operating expenditure was through the roof, production efficiency was poor and exploration was at historically low levels, offering little prospect of staving off a slow decline.
Since then the price has crashed to lows below $30, recovering somewhat to the mid-$50s. The scale of the crisis hitting the industry is demonstrated by the fact that for the first time since the offshore industry began production in 1968, tax revenues in the tax year ending 2016 were net negative i.e. the government paid out £24 million more in tax relief than it received in taxes, while the industry took in less cash than it spent in 2016, for the fourth year in row. With minimal attention in the national press, the brutal discipline of the marketplace has cut the workforce supporting the offshore industry from 450,000 to 330,000 with wave after wave of redundancies.
As a result of relentless pressure on contractor rates, down-manning and the pruning of discretionary spending, operating costs have fallen from an average of £18 a barrel in 2014 to £11.30 last year while a focus on production efficiency has led to an improvement from 65% to 71% over the same period. This improvement in production efficiency, as well as record levels of capital investment approved while the oil price was still above $100, has resulted in a turnaround in production which has been on the increase for the first time in many years: the 322 oil, gas and condensate fields currently in production produced over 1.7 million boe per day in 2016. However, new investment is very dependent on the oil price. Professor Alex Kemp, a leading oil economist based at the University of Aberdeen, argues that at $50 a barrel, new investment activity is stifled and few projects pass investment hurdle rates. Even if Brent crude reaches $60 a barrel, it will be helpful butit is not going to transform the industry as there will still be many fields which remain uneconomic. In the longer term further cost reductions and/or price increases are needed to enhance activity further.
As capital investment is expected to continue to fall from its peak in 2014, the improvement in production levels is likely to be a short-lived respite and total production is expected to begin to fall again within a couple of years, depending on the timing of start-ups. Nine new fields started up in 2016 including Cygnus, Solan, Laggan and Tormore, but only two new fields were approved, though the forecasts for 2017 are slightly better. With just 23 exploration and appraisal wells being spudded in 2013, down from highs of over 100 in the mid-2000s, discovering new fields to replace those reaching the end of their life is increasingly challenging. Most new discoveries are small, expected to produce between 10 and 30 million boe, though some of 2016’s start-ups are exceptions – Cygnus is expected to supply 5% of UK gas demand at its peak while Laggan and Tormore have estimated reserves of 170 million barrels. It’s worth remembering, also, that UK domestic production is still meeting around two-thirds of our oil demand and more than half of our gas demand.
While dealing with the day to day pressures of this financial shock, the industry has also been getting to grips with an overhaul of its regulatory regime. In 2013, recognising the problems facing the industry even then, the government appointed Sir Ian Wood to review existing regulation to see if it was fit for purpose. He recommended a new tri-partite relationship between the industry, a new better-resourced and independent regulator, and the Treasury representing the interest of the nation in its hydrocarbon resources, to make the most of the remaining reserves of the UK Continental Shelf (UKCS).
Swiftly implementing the recommendations of the Wood Review, which reported in February 2014, the government established a new regulator, the Oil & Gas Authority (“OGA”), initially in April 2015 as a government agency and since May 2016 as a government company. The OGA is designed to regulate, influence and promote the offshore sector in a manner better suited to the challenges of an ageing basin, with numerous marginal fields dependent on a network of highly-interconnected infrastructure which is reaching the end of its life. The industry has new legal obligations, incorporated into the Petroleum Act 1998 by the Infrastructure Act 2015, to seek to maximise economic recovery of hydrocarbons in the UK’s territorial waters and Continental Shelf, in particular through collaboration with other industry players, and to comply with a Strategy produced by the regulator to achieve that end, known as “MER UK”.
The OGA has taken over many of the powers and responsibilities formerly held by the Offshore Licensing Unit of DECC, including the power to award licences and grant field development approvals, but the Energy Act 2016 has also given it new powers and greater resources, funded by a significant industry levy. The new powers include powers to attend industry meetings, to request a broad range of information, and to give non-binding recommendations to resolve disputes. The OGA also has a greater range of sanctions to impose on those who fail to comply with their obligations under the licence or the MER UK Strategy, including powers to impose fines of up to £1 million and to issue enforcement notices, in addition to the existing powers to revoke, or partially revoke, licences and remove operators. While the OGA can neither rewrite existing contracts, nor force licensees to invest, it can declare that reliance on existing legal rights is contrary to MER UK, and require licensees who do not wish to invest to divest or relinquish the relevant assets. While such draconian interventions are likely to be rare, and the OGA has to bear in mind the need not to deter investment in the UK, there is a degree of nervousness in the industry as to how the OGA will exercise its very broad discretion.
So far the signals are that the OGA will seek to influence and encourage far more than to compel. This is important. From its relatively recent establishment, the OGA has hit the ground running, having issued a large number of subsidiary strategy documents and delivery plans, as well as establishing a wide-ranging stewardship survey to measure the performance of operators and enable it to benchmark performance, prioritise its regulatory activities, and to develop regional plans for the development of many of the currently uneconomic discoveries. It has also funded seismic studies to open up new exploration possibilities and is investing in better technology to store and share data. The organisation is less than 180 people and so will not be able to solve all of the industry’s problems but its proactive approach is showing signs of success – it claims to have successfully intervened in more than 70 cases already to enable development of discoveries, extensions of field life, unblocking of commercial issues, cost savings and improved plant operations.
A significant legal issue for the industry is how to balance its new statutory duty to collaborate to achieve MER UK with its duties to comply with competition law – this is likely to require more frequent substantive analysis of competition law issues to determine whether or not proposals for collaboration, particularly between operators rather than vertical collaboration between operators and the supply chain, are justifiable on competition grounds.
Not all is gloom. The oil and gas industry is resilient and has been at the cliff edge before. A degree of stability in the oil price, closing the valuation gap between buyers and sellers, has enabled something of a resurgence in oil and gas M&A activity. In the last six months, deals have been signed over almost £5 billion worth of North Sea assets, including Shell’s recent £3billion sale of North Sea assets to Chrysaor, the £993million acquisition of Ithaca Energy by Israeli-based Delek Group and BP’s disposal of an interest in Magnus to Enquest for £68million. Recent transactions have also shown a new appetite for banks to lend and private equity to invest in the sector (the Chrysaor deal was backed by EIG Partners as well with a reserve-based lending package from a consortium of banks while Blackstone and Bluewater Energy have put over £400million into Siccar Point Energy). One of the factors in enabling deals to proceed is the use of innovative structures, such as those offering upside for the seller (for example, in the Shell/Chrysaor deal, an additional $600 million is payable contingent on the average price of oil between 2018 and 2021 exceeding $60 a barrel and a further $180 million contingent payment is dependent on future discoveries by Chrysoar). The sharing of decommissioning liability is also key to transactions since many assets are at the point where their remaining production will not generate sufficient tax capacity to offset decommissioning costs and allow full relief of those costs: Shell has reportedly accepted continued decommissioning liability of $1bn (about 25% of the total cost) of the assets sold to Chrysaor while in its transaction with Enquest, BP has retained the decommissioning liability. EnQuest will pay BP additional deferred consideration of 7.5% of the actual decommissioning costs on an after tax basis, subject to a cap equal to the amount of cumulative positive cash flows received by EnQuest from the transaction assets.
Given the maturity of the basin and its financial challenges, decommissioning is one of the most significant issues facing the industry over the next decades but also a substantial opportunity for the development of a strong specialist supply chain. There are about 250 fixed installations, 250 subsea installations, 5000 wells and 3000 pipelines in the UK sector of the North Sea, with much of that infrastructure being well past its original design life. There is evidence that the oil price crash has resulted in some acceleration of decisions to cease production, but this should not be overstated – while COP dates for 72 assets were brought forward in 2016, 33 were deferred and 135 remained the same. Decommissioning expenditure is currently running at over £1billion annually and it is estimated that over the next ten years around £17.6 billion will be spent on decommissioning. A key plank of the OGA’s activity is to reduce decommissioning costs and therefore the cost to the Exchequer of decommissioning tax relief. Collaboration between operators and the supply chain over best practice and the use of new technology and between operators on multi-well programmes will form part of this initiative but there are also new legal obligations for licensees to consult the OGA before submitting decommissioning programmes for approval. Lawyers are awaiting revised guidelines from BEIS, which now has responsibility for approval of decommissioning programmes, and from the OGA, to see how this process will work in practice. Reducing decommissioning costs will also reduce the ever increasing burden of decommissioning security, required to protect licensees from joint and several liability for the execution of decommissioning programmes, and vendors from the risk of being brought back to conduct decommissioning under the wide powers of Part IV of the Petroleum Act 1998.
Technology however, will absolutely be the key to the continued success of the sector, demonstrated by the opening in Aberdeen of the Oil and Gas Technology Centre, but along with high-tech tools and innovative methods, the industry is continuing to focus on more efficient ways of working to keep costs down, especially through collaboration under the auspices of Oil & Gas UK and other trade bodies. 2017 sees the industry in a more optimistic mood, but aware of the challenges that lie ahead.