A year ago, my colleagues wrote in Outlook 2022 that oil demand was rebounding sharply as the world was emerging from Covid-19 but that, despite increasing oil prices, a wave of investment—as had occurred in previous oil price cycles—would not necessarily follow.
This was because the drive for decarbonisation of the world’s energy sources had put pressure on lenders and other providers of capital to be more restrictive in the provision of capital to coal projects and, increasingly, new oil and gas developments.
The longer-term trend of decarbonisation remains in force and continues to affect oil and gas investment decisions. However, as a result of the Russian invasion of Ukraine and the resulting volatility in the oil price—and in particular the European gas price—there are signs that some providers of capital may be rethinking how they implement their ESG policies. Larry Fink, a leading proponent of ESG investing, stated in a Bloomberg interview in June that energy transition investors “cannot just be mitigating supply; we have to be finding solutions… we need to work with hydrocarbons companies to ensure there is adequate supply.”
In a similar vein, the latest fossil fuel lending policies for Nordic bank SEB indicate the institution intends to work with oil and gas companies with the lowest scope one and two greenhouse gas (GHG) emissions but recognises that “oil and oil-related products will, for a foreseeable number of years, be a necessity to our society”. Generalist asset managers, seeing the high returns and growing dividends being delivered by oil majors such as Shell and BP and other listed E&P companies, are finding they cannot afford not to have exposure to fossil fuels, particularly in light of the recent poor returns being delivered by other asset classes such as bonds and technology stocks.
In this vein a new term—‘the inclusive energy transition’—has permeated debate, recognising more explicitly that we are dealing with a transition that will continue to include fossil fuels (and especially natural gas) for many years to come. While this might be obvious to Petroleum Economist readers, it has gained express acceptance from some policymakers only recently. A case in point is the European Parliament, which in July pragmatically recognised the necessity of including natural gas in the energy transition by designating it as a sustainable source of energy.
However, this designation has no time limit, implying the Parliament has still not landed on any particular timeframe over which it might be realistic or desirable to reduce the use of gas. This contrasts with the view held by some NGOs and members of the public that it is feasible to stop the production and use of oil and gas overnight: a position that recent events have demonstrated would cause severe economic harm. As Ben Van Beurden, the outgoing CEO of Shell, has pointed out, the main impact of stopping oil supply without real adjustment to oil demand will be rising prices rather than global decarbonisation.
In terms of the upstream oil and gas M&A activity we advise on at KLC, we are undoubtedly seeing the effect of the energy transition on investor activity, although it is safe to say that oil and gas M&A will continue for some years, and in some cases the energy transition is itself driving M&A activity. Below are some specific trends we have observed.
Big oil companies are accelerating their pre-existing policy of disposing of late-life upstream assets, especially where doing so reduces their portfolio carbon emissions. A case in point is Repsol’s sale of a 25pc interest in its upstream oil and gas business to US private equity firm EIG in order to release capital for reinvestment in renewables. Another is Shell’s and ExxonMobil’s proposed divestments of their legacy offshore gas businesses in the UK and the Netherlands. The purchasers of these assets will very likely be private funds and private companies.
While these buyers might be less swayed by popular ESG pressure than the majors, it would be too simplistic to conclude they are immune from such considerations or will necessarily be less effective decarbonising stewards of the assets. Regulators will still require these new owners to have decarbonisation plans, and for these assets to be put in ‘the right hands’—meaning those who can devote proper attention to their operation and have the potential to deliver both operational efficiencies and decarbonisation. Demonstrating lower GHG intensity is even more relevant for private buyers that require debt finance for a transaction, as those lending banks that remain active in funding oil and gas projects prefer to allocate their scarce capital and time to lower-carbon projects.
The substantial pressures of the energy crisis on large European industrial gas consumers have also led to signs that such non-traditional E&P players may seek to acquire upstream gas assets to provide a degree of vertical integration and gain protection from unprecedented European gas prices and gas price volatility. It is even possible we could see a reversal of the long-term trend of European utilities divesting their upstream gas assets, as the importance of security of supply and the financial need to hedge downstream supply obligations becomes a strategic priority.
The opportunity to repurpose oil and gas assets for the energy transition is also driving new business models and changing the mindset towards decommissioning in some instances. The ability to redeploy depleted gas reservoirs for CO₂ sequestration, hydrogen storage or increased natural gas storage can turn late-life gas fields from being near-term decommissioning liabilities into useful storage assets.
The recent reopening of the Rough gas storage site by the UK’s Centrica is a great example. Centrica had considered sale and full decommissioning of the field, and had been pursuing CO₂ or hydrogen storage solutions, but the strategic imperative of enhancing UK security of energy supply has instead created a viable future for it as a gas storage business. Elsewhere, especially in Central Europe, increased focus on the repurposing of onshore oil wells for geothermal energy production can provide a source of renewable heat and/or electricity generation for oilfield operations, or in some cases for local communities.
Finally, a continuing trend we are seeing in deal-making is that upstream M&A deals are taking longer to close than has typically been the case. The causes for this are varied and case-specific. It is possible that, as public scrutiny—including challenges from NGOs—on regulatory decision-making increases, the pace of approval processes is slowing down, as regulators wish to take more time with their decisions. The fact that buyers are increasingly private companies, often with lower credit quality, has also in some cases extended the process and time required for joint-venture partner consents.
Overall, the M&A market for upstream gas developments in Europe and oil and gas developments in Africa remains strong, supported by high prices for both commodities. Although the energy transition is clearly affecting upstream oil and gas M&A in some of the ways mentioned above, the secondary market for upstream assets remains active. In our view, this indicates that the energy transition continues to include oil—and especially natural gas—as essential parts of the energy mix. However, the energy transition also means the identities and strategies of the owners of these assets continue to evolve.
Paul Dufays is the director at the energy advisory company, Kirk Lovegrove & Company.
This article is part of our special Outlook 2023 report, which features predictions and expectations from the energy industry on key trends in the year ahead. Click here to read the full report.