Europe’s upstream comes under pressure [NGW Magazine]

There is a tension between the social pressures driving a number of European governments to set dates for achieving net-zero carbon economies on one hand, and the advantages of producing more oil and gas at home on the other.

The focus on environment, social and governance (ESG) issues has risen far up the agenda of banks and investors. Shareholders too are becoming increasingly active.  

But all things being equal, there are short and long-term benefits to retaining an upstream industry, apart from the immediate tax benefits.

The balance of payments is improved; jobs and skills that will be necessary for a low-carbon economy are retained; infrastructure is used and maintained in readiness for repurposing after the long period of research and development of new technology; and the carbon footprint of imports is reduced.

The UK upstream group OGUK says governments must keep an eye on the importance of indigenous resources: failure to do so will not bring wider economic or environmental gains.

An example of the spin-off gains is provided by Neptune Energy, backed by private equity firm Carlyle. It entered the upstream after the last oil price crash, initially buying up French Engie’s unwanted upstream assets.

It has contributed to the economies of the countries where it operates, claiming that last year its European activities supported 11,400 jobs and contributed $2.1bn gross value added, spread across its UK ($459mn), Norwegian ($1bn), German ($296mn) and Dutch ($343mn) operations.

Oxford Economics (OE) has calculated that for each Neptune employee in Europe last year, the company supported nine more.

At the same time it has adapted to the changing regulations on methane leaks and so on and is poised for further growth, embracing offshore electrification and lower carbon initiatives. OE said the impact of Neptune's activities extends “well beyond its core function of producing energy. This includes developing emissions reductions plans in its operating countries and scaling up partnerships and investments in low-carbon technologies such as carbon capture and storage, hydrogen and electrification.”

Licensing rounds

Commenting on the ongoing government review of the licensing regime amid speculation that it might be suspended altogether ahead of the COP 26 meeting in Glasgow late this year, OGUK said that a successful transition to a net-zero carbon economy depended on a strong domestic oil and gas industry.

Maximising the proportion of UK demand that is met from domestic resources will help limit exposure to global trends and help to reduce overall carbon emissions, with domestic production having a lower footprint than LNG imports, it said.

Denmark announced the end of new production licences last year when it scrapped the eighth licensing round, forgoing some $13bn in future revenues.

Rather than scrapping licences, the director of Petroleum Development Consultants David Aron told NGW: “The UK government would be able to improve the situation for producers if it reversed the fiscal policy and allowed producers to offset exploration costs against tax as happens in Norway. That would encourage exploration.”

Ireland has also toyed with banning licensing rounds, even though when its main field Corrib is depleted, the country will depend either on LNG or on pipeline deliveries from further afield, both of which are worse environmentally, Aron said.

It is not only the upstream that sees a good future in the UK: in its ‘Balanced Pathway’ scenario, the Climate Change Committee says the UK will consume more than 17bn barrels of oil equivalent through to 2050. This is more than half the total cumulative energy expected to be used in the UK.

Key to realising the 2050 UK target is the long-awaited North Sea transition deal with government, which OGUK says could be an “important catalyst for unlocking the full contribution that the industry can make to achieving net zero.” The deal would also help ensure that as much of these new opportunities as possible are seized by UK supply chain companies (Figure 1).

Wave of M&A

Even without the transition deal though producers seem to take the regulatory changes in their stride, judging from the wave of mergers and acquisitions (M&A).

OGUK calculates that assets worth some $2.8bn and representing 330mn barrels of oil equivalent have changed hands just in the first few months of the year.

The all-share takeover of Premier Oil, announced last autumn, is due at the end of this month and catapults privately held Chrysaor – to be known as Harbour Energy – into the top league of UK producers.

A partner at energy law firm Bracewell, Jason Fox, told NGW: “We are seeing an exceptionally high level of North Sea M&A activity at the moment.

“Much of it is a continuation of the trend we have seen for some time of majors and supermajors disposing of assets to independent exploration and production (E&P) companies, though we have seen some trading between independents also, such as the recent disposal of Zennor Petroleum by Kerogen Capital to NEO, a HitecVision backed E&P company.

“Private equity (PE) is backing the buyers of many of these transactions but there is a reducing number of PE houses with the appetite for North Sea acquisitions. With so many North Sea assets up for sale and access to capital suffering from increasing ESG pressure it remains to be seen whether they will all find buyers," he said.

Other deals done in the UK this year include EnQuest’s purchase of Suncor’s stake in the Golden Eagle field; Waldorf Production’s purchase of Cairn Energy’s stakes in the Catcher and Kraken fields; and DNeX has increased its shareholding of Ping Petroleum.

The rationale for M&A varies. For sellers, it has been the opportunity to cut costs in a mature province and focus on higher-value barrels elsewhere in the world. In the case of ExxonMobil, these have been in the US and offshore Guyana, among others.

But while it has sold most of its UK and Norwegian upstream businesses, it remains tied to the gassy UK southern basin, where it is partnered with the Anglo Dutch major, Shell.

ExxonMobil declined to comment on the reasons for the retention but CEO Darren Woods said March 3 that the foundation of the ExxonMobil business was “competitively advantaged assets and investments…. We have, in our portfolio today, the best set of opportunities we've had in over 20 years.”

Aron told NGW that ExxonMobil needs the gas from the southern basin as one part of its decarbonisation strategy. “They need to get their carbon footprint down. Besides as Shell Expro operates the assets there is little that any company could do differently, even if it did agree a sales price.”

The Anglo-Dutch major though is not quitting: it sold some assets to Chrysaor a few years ago but is investing elsewhere in the UKCS, including partnering Deltic Energy in at least one well in the southern basin.

French Total too has been expanding, taking a position around the West of Shetland as a hub.

Aron agreed that there was “definitely a wave of new entrants” coming to the North Sea, but said it is not clear what the theory behind it is.

“They do not need such a high rate of return as unlike the international oil companies, they will not be drilling many dry wells that need paying for. And there is already infrastructure in place, which was not the case when the international oil companies first developed the province. But it is not clear how much longer the pipelines will be operational for.

“And companies with money cannot leave it in the bank at these rates so they might as well put it to good use by backing a new upstream company.

“But why the North Sea? why not North America, east Africa or some other oil and gas province? The UK's legal and regulatory frameworks are well known and there are big, liquid markets for oil and gas. On the other hand the focus is tightening on net-zero carbon. It is not clear to me what the attraction is,” he concluded.

OGUK says companies continue to face a range of pressures such as investor confidence, changes to regulatory and policy frameworks and work to incorporate net zero considerations into projects.

Raising the bar

The UK upstream regulator, Oil & Gas Authority (OGA) meanwhile continues to exhort its clients to ever greater acts of decarbonisation. Its Stewardship Expectation 11 which it published March 15 explains what the licensees must do or demonstrate at each stage of a project’s life-cycle in order to support the UK’s net zero target and retain the social licence to operate.

From 2023, ESG reporting will be mandatory and initially the items are expected to include data on flaring, venting and fugitive methane emissions, alongside scope 1 & 2 emissions; health and safety statistics; and carbon intensity.

The OGA set up an ESG taskforce when it saw a gap between the expectations of the investor community – which is itself coming under pressure to play a greater role in supporting low-carbon business – and what was actually being reported.

OGUK says it “shares the OGA’s commitment to deliver the UK’s net zero target with ambitious plans for emissions reduction” and that “companies across the UKCS are looking to reduce emissions across all aspects of their upstream operations, working closely with their supply chain to do so, including through CCS and hydrogen production, both of which are key to the cleaner energy systems of the future.”
Operators and licensees will have to align to a common minimum standard of reporting with a view to report in Q1 2022 alongside the publication of their 2021 full year audited financial reports.