Companies involved in oil and gas activities globally are tightening their belts. The decline in the price of Brent crude oil (spot sales) from $115 in June 2014 to less than $50 per barrel in just over six months represents a loss in value of over 60%, leading to a reduction in profits (and for some, no profit at all). Regardless of the macroeconomic effects for GDPs, the economics presently look stark.

Some recent headlines demonstrating the devastating effect of the rapid oil price decline:

  • mega mergers and redundancies in the oilfield service sector;
  • the announcements by BP, Talisman and ConocoPhillips of job losses in their North Sea workforces and other operators looking to change the typical “2 weeks on, 3 weeks off” rotation pattern;
  • projects put on hold in Qatar and the Canadian oil sands, (Russia’s Shtokman project and US shale developments are also feeling the pinch);
  • Shell announced last week it will curtail $15bn of investment over the next three years; and
  • across the board rate cuts for North Sea contractors have been implemented since January.

Difficult times for the North Sea

All this comes at what was already a difficult time for the North Sea industry. It is worth noting that some companies were exiting the UK Continental Shelf (UKCS) even before the price crash and that much of the investment, and growth in the UKCS is expected to be in more expensive “frontier” areas. But now, according to a survey of forecasters conducted by The Independent, the oil price is almost at a point that every barrel produced in the North Sea would be unprofitable. There have been calls for a 50% drop in taxes applicable to the North Sea, as 100 (out of around 300) fields were said to be in danger of being shut in.

Faced with such a drop in the price of their product, operators of producing fields have four choices: (i) sit tight and hope prices bounce back quickly and sharply, (ii) cut costs and/or investment, (iii) shut in production or (iv) lobby the Government to boost their net revenue by changing the fiscal position. We’ve seen some examples of option (ii) already, as noted above. Companies opting for option (i) may wish to consider overlifting or underlifting their share, within the confines of joint venture arrangements, to ease immediate cashflow worries (and see our previous article for issues to consider dealing companies potentially in distress), or gambling on a return to higher prices, respectively. Here we consider options (iii) and (iv) in more detail.

Shutting up shop

Operators of producing fields might consider shutting in production (i.e. stopping production and shutting wells), either for a temporary period until the oil price rises back to a profitable level or permanently with a view to beginning decommissioning. Below, we take a look at some of the practical and legal consequences.

Recommissioning facilities after a temporary shut-in can be a costly and lengthy process. This can be prohibitive, leading to remaining reserves being left in the ground. According to reports it took BP’s Rhum field (temporarily shut in between November 2010 and October 2014) a year to recommence production due to technical delays after receiving approval from DECC.

Those who choose to shut in production with a view to decommissioning must undertake decommissioning activities in accordance with pre-approved programmes. Early field decommissioning can also result in the premature decommissioning of ageing infrastructure which could otherwise be used by newer fields.

But before an operator can take steps to shut-in production, it must follow a process and obtain certain approvals (which may or may not be forthcoming). Prior to engaging with Government, the operator must obtain approval from its other joint venture parties in accordance with the voting arrangements in the relevant joint operating agreement.  If the green light is given, the operator will need to seek approval in accordance with the law and licence conditions.

Secretary of State blessing

DECC regulates producers operating in the UKCS through the Petroleum Act 1998, as well as the licence conditions in offshore exploration and production licences granted to companies wishing to explore and produce oil or gas in the UKCS. These conditions are drawn from “model clauses” set out in secondary legislation. The model clauses used vary depending on when a licence is granted. But a general principle applying across model clauses for all licences (regardless of when the licence was granted) is that the Secretary of State for  Energy and Climate Change’s (the Secretary of State) consent or approval is required for certain key steps. Under the licence conditions, a licensee cannot abandon any well, nor may it decommission any assets, without the Secretary of State’s consent. Therefore any decision to shut-in a well governed by a UKCS licence requires the Secretary of State’s blessing.

The Secretary of State has the power to revoke a licence (in respect of one or all licensees) on a failure to comply with licence conditions and may direct at the time of revocation that any well drilled is left in good order and fit for further working; thus providing the possibility of future production.

MER UK

The results of prematurely shutting in production seem diametrically opposed to the Government’s aims of maximising economic recovery from the North Sea resource (MER UK) (in line with the proposals set out in the Wood Review). Prior to the coming into force of the Infrastructure Bill, there is no legal requirement for the Government to take MER UK into account when exercising its licensing and decommissioning functions. It is bound to be a factor in decision-making on any request for Secretary of State consent. The Infrastructure Bill, when in force, will also place obligations on producers (see our previous blog) to act in accordance with the Government’s MER UK strategies. 

Death and taxes

There may be nothing more certain than death and taxes, but taxes applying to the UKCS have been far from certain. The surprise increase in the Supplementary Charge from 20% to 32% in 2011 (due to the high oil price) serves as a reminder to the industry of the temptation to shock (but without awe).  Analysts and industry experts believe that what is needed is (i) a quick fix reduction on tax rates to show UK plc supports the North Sea industry (and help those still making a profit) and (ii) a comprehensive review of the tax system in place to reduce complexity.

Head of Oil and Gas UK (OGUK), Malcolm Webb, would like to see “30% as the top tax rate”, whilst “some companies are paying 80% as the highest rate on fields in the North Sea.” How is it that some companies are paying 80% in tax? The Government currently operates three oil and gas tax regimes, which overlap with each other, as follows:

Click here to view table.

First steps for improving fiscal competitiveness

The Government did respond to the oil price change in December 2014 announcing various reliefs, including cutting the Supplementary Charge from 32% to 30%, extending the ring-fence expenditure supplement for offshore oil and gas activities for four more years as well as plans for new “cluster” allowances. The industry commended these steps, but they were felt not to go far enough. In addition, these reliefs may be more helpful for those engaging in exploration in newer frontier areas than for those producing from the older fields with marginal economics. With the oil price dropping lower (and the potential for sub-$40 Brent crude), in mid-January, Sir Ian Wood, whose Review recommended a wholesale review of the tax structure to encourage investment in the interests of “MER UK”, advocated lowering the Supplementary Charge within the next few weeks by at least 10%, i.e. back to 20%.  Malcolm Webb’s view is that the December “measures can only be seen as the first steps towards improving the overall fiscal competitiveness of the UK North Sea. We will certainly need further reductions in the overall rate of tax to ensure the long-term future of the industry”.

Part of the problem is that the UK operates a licensing regime for exploration and development activities, and the Government obtains revenues from the UK’s natural resources through imposing taxes. As a result every response from the Government to market conditions, or attempt to stimulate activity, takes the form of legislation that applies to everyone and tends to hang around. Other jurisdictions, which operate production sharing regimes, have the luxury of adapting production sharing formulas (often set out in contract) to reflect the level of exploration risk for a particular concession or block, with regard to factors such as geographical location and drilling depth, by allowing the parties’ shares to increase or decrease as aggregate production increases. Those operating in such regimes may also benefit from stabilised taxation for a certain period of time (contributing to the attractiveness of a jurisdiction for investment).

OGA to the rescue?

Whilst the UK has tried to import some mechanisms into the tax system to allow for the recognition of risk in exploration, some commentators feel the UK now fields a convoluted and newcomer-unfriendly fiscal system. As the competition hots up between countries to provide home for petrodollar investments, this provides an opportune time to review the tax system for the North Sea. It seems that the new Oil and Gas Authority is getting cracking undertaking a review of measures which could be taken to relieve the existing crisis.