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JOG goes back to the future

A field already in decommissioning holds no fears for the North Sea newcomer’s bold regional plans

UK independent Jersey Oil and Gas (JOG) has an intriguing proposition—putting 21st century infrastructure on a 20th century Central North Sea (CNS) field. But its plans are more than that initiative, also encapsulating an area hub concept and collaboration, as well as a laser focus on ESG.

At the core of JOG’s plans is the CNS Buchan field, which began production in 1981 under BP’s operatorship and continued to flow oil —148mn bl of it—until 2017, when the original facilities failed safety tests. Then owned by a joint venture between Spain’s Repsol and China’s Sinopec, the decision was taken to permanently shut down production and decommission its facilities.

Meanwhile, in the downturn that followed the 2014 oil price crash, JOG acquired access to the P2170 licence, in which it identified the Verbier exploration opportunity. It subsequently farmed out a stake in P2170 to Norway’s Equinor, which lead to a drilling programme and, ultimately, an oil discovery. In January, Equinor sold its 70pc Verbier stake back to JOG, which the latter views positively as its now 88pc share gives it greater control.

In 2017, Equinor’s lower end estimate for recoverable reserves at Verbier was c.25mn bl, which may not have supported a standalone development. This motivated JOG to broaden its focus more regionally across the Greater Buchan Area (GBA).

And the UK’s oil and gas authority (OGA) launched its 31st supplementary licensing round at the start of 2019, including the Buchan blocks which Repsol-Sinopec had handed back to the government. JOG “was quick off the blocks” to secure it as licence P2498, says its CEO Andrew Benitz. The previous year, alongside Equinor, it had pre-funded a major new 3D seismic survey across 1,000km² of the GBA, well beyond the borders of its existing licence, aiding its grasp of the opportunity.

“There are at the moment, and will be more, distressed assets out there that the right company and the right team could take advantage of” Lansdell

And this wider regional approach is key to JOG’s thinking, as it looks to the future for not just Buchan and Verbier, but resources in the Buchan Andrew, J2 and Glenn discoveries. It has also identified up to six other near-field exploration opportunities in the Verbier licence, as well as three prospects in the P2497 licence directly to the west of Buchan—142mn bl of net contingent resources and 232mn bl of net prospective resources in total.

But JOG is also looking beyond its own licences. In March, it established and is leading a GBA joint integrated studies agreement between neighbouring field operators, covering technical and commercial evaluation of a collaborative development of the wider area. This potentially brings in the Avalon discovery, operated by Malaysia’s Ping Petroleum, and UK independent Zennor  Resources’ Leverett.

Benitz is also aware, though, that other CNS infrastructure is ageing and end-of-life for certain pipelines and gathering centres could leave dependent fields with production life left in them stranded without evacuation options. Indeed, this has already happened to some fields dependent on the now shuttered Theddlethorpe gas system.

As the putative developer of what could be one of the last new CNS infrastructure projects, Benitz has his eye on the business opportunity of offering ullage in the new Buchan facility to proximate resources that may need an alternative export option. Petroleum Economist spoke to him and JOG COO Ron Lansdell to find out more.

What you are proposing to do with the Buchan field—not simply restarting production from what is there but putting entirely new facilities onto a field where previous infrastructure has been decommissioned—is that unique?

Benitz: There have been a few cases in the North Sea where companies have gone back in to try to redevelop a field that has ceased production due to natural depletion—using enhanced oil recovery to squeeze out the last drops.

Where our project is distinct is that Buchan did not stop producing because of natural depletion. It was still producing, albeit from a couple of vertical wells drilled in the 1980s that did not have any of the benefits of modern technology.

It stopped only because its floating production vessel was a converted drilling platform which had failed its safety case in 2017.  This production vessel was chosen when it started producing in 1981, when Buchan’s reserves were initially estimated at 50mn bl and its producing lifespan at just five years.

“80mn bl Remaining Buchan reserves

As two independent competent person’s reports have concluded, there is still a very material amount of oil, 80mn bl, still to come out of Buchan. So, we think it is unique.

Lansdell: The remaining reserves is an important point. There are industry concerns and rumours out there that Buchan has run out, there is nothing left, etc. There is a lot of oil down there. We are confident that, once concept select is completed, we will demonstrate the economic viability of bringing this back into production.

Is it fair to say you have very much put Buchan’s environmental impact at the centre of your thinking?

Benitz: Fundamentally, we see the energy transition as an opportunity, rather than a challenge. Our industry has the potential to be part of the solution. For a project like GBA, with a projected 2025 start date, we can really start to plan how adopting modern technologies can contribute to that lower carbon future.

One of the things we have been looking at is power solutions for the GBA. What we concluded from the first phase of our investigations is the technical feasibility of power from shore. And if you look at projects across the maritime border in Norway, such as Johan Sverdrup, platform electrification has been adopted and has been highly successful.

Power from shore obviously reduces carbon emissions from the field’s production. The global average for emissions from output from offshore infrastructure is 18kg CO₂e/bl produced, in Norway the average is 8kg CO₂e/bl, on Johan Sverdrup it is less than 1kg CO₂e/bl.

But it goes beyond that. It makes your facilities simpler and safer. It means less maintenance, so fewer flights to and from your platform, which further reduces the carbon footprint. And what we have found from looking at other power from shore fields is that the uptime tends to be much higher, so it raises efficiency across the lifecycle of your project and brings your opex lower.

We are at a very early stage, but we are also looking at whether Buchan, within the GBA, could be not just a production hub, but also possibly a power hub— not just using the electricity delivered via cable for shore on Buchan, but also collaborating with other regional operators for their power needs.

And, a lot further down the line, the Buchan reservoir has been identified as potentially suitable for carbon storage. That really fits into our thinking about the project’s overall carbon footprint across its whole lifecycle, right from beginning to end. We really want to think holistically about this project. We ultimately think it will make the project more sanctionable and more investable.

“We see the energy transition as an opportunity, rather than a challenge” Benitz

You have no production, no debt, over £12mn in the bank and are fully funded through to the end of 2021. How does that make JOG’s experience of the current oil price environment very different to a lot of other oil firms?

Benitz: Without doubt, the industry in general has been negatively impacted by Covid-19. But, in relation to us as a company, we are in a relatively stronger position—we have cash, we have no debt, we are funded through concept select, which we aim to deliver this summer. And we have got a really exciting, large-scale, conventional project in the heart of the CNS.

Obviously, we would shut up shop if we did not think oil demand was eventually going to come back. Globally, there are still developing countries that are going to be increasingly energy hungry. And on the supply side, particularly given the current situation, capex under-investment is going to emerge as a real problem for the industry.

That is going to lead to a supply crunch somewhere down the line. It may have been delayed by coronavirus, but it will come. And our project, which has first oil scheduled for around 2025, is perfectly timed for recovery.

So, we do think that this is an attractive development and, once we get through concept select, we plan to launch a sales process to bring in industry partners. That will be a key component of meeting funding requirements for the project. We think it will appeal to any players faced with declining production and needing to replace  reserves.

In that sales process, would you be looking solely for cost carry or an upfront payment?

Benitz: We would be looking at a combination. We are aiming to maximise value from a sales process and pursuing both would be the way to do this. We have put together a very capable project team, who have done this sort of thing before. And, because the GBA is our single focus, we are in a pretty good position to take it forward.

Could Equinor’s exit from Verbier be seen as somewhat of a negative for the overall GBA concept?

Benitz: If you look at it on an isolated basis, you could see it as a negative. But you have to appreciate what Equinor was focused on. It came into the area with a focus to explore Verbier. Verbier turned out to not be as big as might have been hoped for. So Equinor decided that it did not rank sufficiently highly from a portfolio capital allocation perspective. Equinor may have walked away but, because we have taken a regional approach, we have taken on and matured the GBA as a whole into a larger, more attractive, more deliverable position.

Are there any advantages that the curent price downturn could offer to you going forward, for example lower contracting costs for services?

Lansdell: We are not currently building any cost reductions into our price forecasting, mainly because services pricing never fully recovered from the previous downturn. It would be nice to hope for, but we are not accounting for it, we are using contractors’ existing pricing in our planning.

And could JOG take advantage of any falls in asset prices to look at possible acquisition opportunities?

Lansdell: If you go back to the very beginning, JOG was founded by reversing into a company that was in not particularly great shape. So, it remains part of our strategy to look opportunistically at what might be out there. It is not our core focus at the moment, but if something came in and we thought, “that is a good price, we could make money from that,” we would not disregard it. There are at the moment, and will be more, distressed assets out there that the right company and the right team could take advantage of.

Benitz: With our focus on developing the GBA, we see that M&A could play a role in being able to fund capex going forward. Acquiring cashflow generating producing assets at an acceptable price could be on the cards.

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