Funding E&P in the UKCS
After a number of very difficult years, a spirit of measured optimism has returned to the North Sea oil business.
Brent may have dropped below US$60 per barrel, but confidence in a US$50 to $70 band seems to hold; deals are happening in the E&P sector, as well as in the all-too-recently blighted service sector.
It’s encouraging that despite the attractions of investment into North American shale plays and locations such as Mexico, the UKCS continues to attract development, if less exploration, capital.
The last year has seen the growing trend for the majors to decouple from the basin: ConocoPhillips, Chevron and Marathon Oil have recently done major exit deals; Total has swallowed Maersk Oil. Meanwhile new or newish players such as RockRose Energy and Delek Group are proliferating, and production is showing a welcome increase.
And in March, the Oil and Gas Authority (OGA) said oil and gas production in the UK increased by more than 4% in 2018, averaging 1.7 million barrels of oil equivalent per day.
The funding hurdle
Meanwhile, the biggest challenge for the OGA is to ramp up exploration drilling rates, but given the cost and risk base of the UKCS that’s still a difficult proposition.
Add to that, in the world of E&P at least, money is still hard to come by, especially when it comes to smaller or less conventional fields such as tight sands, high-pressure, high temperature finds and heavy oil.
Money raising is also difficult if you’re a smaller company, especially if you have no portfolio or are a one asset business.
In the depths of the oil recession, it became common for oil service companies to offer to self-fund development costs on a deferral basis with repayment to be made out of production on generous terms. Of course here, the service company takes the production risk, at least for part of its services.
We have been dealing with deferral funding regularly for the last two years and, in our experience, some service companies have begun to retreat from the practice in line with an improving market.
Some oil service companies undoubtedly suffered bad experiences when production either didn’t occur or disappointed; however, we continue to find that certain oil service companies are willing to provide this kind of financing, not usually on a 100% basis, for appropriate development projects.
The role of royalties?
We are also finding that royalties are increasingly being used in deal-making.
A royalty is paid out of subsequent production. If used as deal consideration, it will reduce or eliminate the seller`s upfront compensation. Typically, the buyer will make subsequent investments and obtain or increase production.
In many jurisdictions, royalties are also used to secure financing, but it’s harder to do this in the UK because here, a royalty is merely a contractual agreement between the royalty grantor and grantee and cannot be secured directly.
A financial institution looking for security through a royalty would need to take a security over the licence. In any event, creation of the royalty would need explicit approval from the Oil & Gas Authority. In such an arrangement, some argue that a royalty owner could be at risk of being held liable for decommissioning via section 29 of the Petroleum Act.
It may be that the OGA and Oil & Gas UK should consider steps to regularise royalties and royalty financing as companies coming from other jurisdictions, such as Canada, find that the UK is not progressive in this respect.
Apart from anything else, it would be useful to work on a standard form royalty deed whose terms would meet OGA regulatory requirements. An “open permission royalty” could follow the successful example of “open permission” joint operating agreements.
It is worthwhile clarifying that a royalty owner can’t ever be held liable for decommissioning under section 29. The law might also be changed to allow overriding royalties to be subject to security devices to allow them to attain secured status in bankruptcy.
This article previously appeared on the Energy Voice website.