Vadim Yakovlev: Our plan remains the same – to reach production of 100 million tonnes!

Gazprom Neft's YouTube channel

One hundred million tonnes of oil equivalent (mtoe) is the strategic goal Gazprom Neft has set itself to achieve in the next two years. We discuss the company’s growth points and strategic development to 2030 at its Drilling Support Centre, having first been given a glimpse into the future by First Deputy CEO and Head of Gazprom Neft’s Upstream Division, Vadim Yakovlev.


Gazprom Neft's YouTube channel

— Gazprom Neft’s strategy suggests the company aims to be producing 100 mtoe by 2020. Output in 2017 was about 90 mtoe. Is your strategic goal achievable?

— Our plan remains the same — to move towards producing 100 million tonnes. Growth in 2018 is running at 2.5 to three percent up on 2017. What happens in 2020 depends not just on our opportunities and intentions, but also on how far agreements might change under the OPEC+ deal.

Generally, in order to maintain the sort of growth that will allow us to meet our strategic goal, we need to invest about RUB250 billion in exploration and production every year. One hundred million tonnes of oil will put us among the world’s top-10 biggest companies in terms of production volumes, and we are determined — at the very least — to remain among the big-league producers, thereafter. To do that, we need to maintain growth at least in line with the industry average. Our projections suggest demand for oil will show steady growth, of 1.5 to two percent per year, to 2030. This marks the lower end of our objectives in terms of production growth.

— This new strategy, determining the company’s development beyond 2025 — is it based on any new principles, or is it the logical extension of existing plans?

— The strategy we’re currently working on accentuates scale rather than quality of growth. We plan to maintain our leadership in terms of ROACE, to secure the maximum possible profit on every barrel produced, and to become the best in the industry in terms of qualitative criteria such as efficiency, safety, and technological adaptability.

Which projects are front of mind, in the long term? Will it be possible, for example, to go into commercial production at the Bazhenov Formation in the space of 20 years? Or is that such a remote possibility that there’s no point in counting on it, even in terms of strategic planning?

We’re planning on non-conventional oil making up three to four percent of our volumes by 2025, and up to 10 percent by 2030. That’s a very ambitious task, and if you’re talking specific figures you have to take the long view. The first oil obtained from the Bazhenov Formation cost about RUB30,000 per tonne — we’re now at a level of RUB18,000 per tonne. Our target is about RUB8,500 per tonne. That level would allow us to bring the Bazhenov reserves into commercial development. And that’s one of our strategic bets with a very clear — and a very wide-ranging — perspective. Although the level of uncertainty is very high. For that reason, we’ve got several opportunities like that in our strategic project portfolio.

— And what are the main strategic growth points?

— The main area for growth is in the north of the Yamalo-Nenets Autonomous Okrug. Firstly, this continues the development of fields already brought into production — the Novoportovskoye field, and the Messoyakha group. We’ve got licenses for a further four blocks, where we’ll be actively prospecting for hydrocarbons over the next three years. It’s not yet clear what these reserves are likely to be — oil, gas, or a combination of these — but we’re confident of their supplementing the resource base. We’re expecting to bring these assets into development from 2022.

Implementation of a range of projects that might reasonably be termed “growth points” has already begun. This includes oil-rims of the Yen-Yahinskoye field, the Pestsovoye and Tazovskoye fields, and Achimovsky deposits — present, for example, in the Severo-Sambursky license block.

Drilling-out at the Prirazlomnoye field is ongoing. Further investigations are now in hand at the Dolginskoye and Severo-Zapadny licence blocks on the Arctic shelf. So we’ve definitely got a promising resource base.

— There’s been a lot of talk — for more than a decade — to the effect that oil and gas, as resources, belong in the past. What do you think about that?

— You’re right when you say discussions have been going on for several decades. Attempts to reduce the proportion of fossil-fuel sources in the global energy balance have been going on for more than 30 years. At the time, that proportion was about 81 percent: and now — it’s still the same 81 percent.

Obviously, we take the rapid development of alternative energy into account in our strategic scenarios, and assess how this might impact our long-term development. At the same time though, we’re not about to dramatize the situation, either. I think the development of alternative energy sources means we have to become ever-more efficient — and that means more competitive — even in terms of the 2030–2040 perspective, when demand for our products could start to decrease. We need to earn more than our competitors. If we see that one kind of alternative business or another is effective, and it’s worth including it in our portfolio, then we need to put the financial resources in place to enter that market segment. At the moment, ultimately, we don’t think it’s appropriate, at the venture stage, risking hundreds of millions of dollars per quarter to be involved in alternative projects.

What areas are of interest to Gazprom Neft geographically, and what international partners is the company considering cooperating with?

— We see the Middle East as a strategic area of operation, and are actively looking for additional options in projects we’re already working on — i.e., Badra, Kurdistan. We expect our partnership with the Mubadala fund to deliver an outcome here, and to give us the opportunity of evaluating and getting involved in additional assets.

But generally, if we’re talking about development abroad — we’re selective, now, and will be selective going forward. The one overriding condition in considering the potential of projects abroad is — to secure an effect comparable to what we are achieving in Russia. Russian assets are very good in terms of generating income, and that means international assets have to generate ROCE of 15 percent, at the very least. Finding projects abroad that can genuinely compete with development opportunities in Russia is far from straightforward.

— Sanctions aren’t impacting development?

— I would remind you, only two industry sectors, in fact, are currently subject to sanctions: deep-water production and shale oil. All the rest of the industry is open for partnerships. Nonetheless, there is this stereotypical view that you either can’t work with Russian companies at all, or that cooperation has become far more complicated. After the Mubadala deal they were simply overwhelmed with questions — how and why had they taken on that sort of risk — although, in fact, there were no restrictions at all. There have been situations where international companies have refused to supply equipment for our projects — for example at the Novoportovskoye field, which isn’t subject to any sanctions at all. Obviously, we found an alternative solution, and those foreign partners still with us are now proud of their involvement in such a landmark project.

— The oil and gas industry has a very long investment cycle, so the question of predicting the tax system is extremely important. Are you conducting any negotiations on this, consulting with government? Do you have any understanding as to what’s going to happen here over the next 10 to 20 years?

— Negotiations — that’s certainly the word for it. It does have the look of very difficult discussions, with a very clear division between both sides. And with that approach it’s pretty much a zero-sum game. That’s probably happening because the focus in these discussions is extremely short-term — the prevailing issue in these discussions being not the question of budgetary risks, or potential tax losses. Ours is definitely an industry with a long investment cycle, so we have to think in terms of the next 10, 15, 20 years. But there’s almost no discussions on such far-off prospects between us, the government, and pretty much all industry participants. If government sets itself the job of securing a stable source of income for both the state and the industry for years to come, then I think there’ll be a cardinal change in the nature of the discussion. More than anything else, we need to talk about adding value, and the question of how we then share this among everyone involved in the discussion is a secondary issue.

No consensus, per se, has been found; additional mechanisms for interdepartmental interaction are needed — we need groups from government, from industry, to think for weeks, months, years: however long it takes to create added value.

— Can you give a concrete example demonstrating these inconsistencies?

Yes, ASP-flooding. We have been involved in a pilot project with Shell on implementing this technology at the Salym field. We’ve had a very impressive outcome, with the ORF (oil recovery factor) reaching as much as 69 percent. That’s unprecedented in Russia’s oil industry. Under the current tax system, full-scale implementation of this technology is impossible. At $70 per barrel, about $30–40 is taken from us automatically, and we have to finance production and business development from what’s left. Ultimately, total costs turn out to be higher than what remains to us once taxes are paid.

We can’t operate at a loss, so we’re prepared to invest in developing technology if there’s a another tax tier between the government and the subsoil user that takes into account actual costs, and the actual profit from this extra oil. The effect of using technology — even on the fringes of Gazprom Neft’s activity — would be about 250 million tonnes of additional recoverable reserves. Industry-wide, that’s billions of tonnes and dozens of billions of dollars’ additional income, with zero investment on the part of the state. But for some reason that’s of no interest to anyone apart from us.

— Nobody’s considered what sort of tax tier would make this project, specifically, effective and viable?

— There are several options. The ideal mechanism would be to apply the Excess Profits Tax (EPT), which is based on the premise of profit first being generated, and only then allocated in terms of the tax we pay to the government, with a proportion remaining with the business. But this project doesn’t benefit from the EPT quota, because production is too high at the Salym group of fields.

There is an alternative option: a mechanism for deducting additional expenditure from the Mineral Extraction Tax (MET), or by applying a reducing factor in calculating MET where technology is being utilised, and can be accounted for. Accounted for in terms of technological parameters, and in terms of the amount of investment the company or subsoil user has to make in order to make a claim under such alternative tax mechanism. Calculation algorithms could be put in place separating basic production from the additional oil obtained through using such new techniques. There just needs to be a serious conversation, in order to find a solution.

— Gazprom Neft has, already, been implementing its technological development strategy for several years. Have there been any genuine achievements?

— In terms of something that has already delivered a direct economic effect — modern drilling technologies, and the introduction of cutting-edge fracking techniques. We’re getting at least 10 million tonnes of production every year through developments here.

Added to which, we’re not just improving our capabilities in terms of technology and equipment, but are working very hard at making technologies cheaper, since reserves are becoming ever more complex and production, accordingly, more expensive. For example, in Orenburg, by adapting well construction we’ve been able to increase drilling speeds by 50 percent. In Megion, moving over to dual-string well completion has saved 30 percent in well-construction costs. We’re now introducing these approaches at other assets.

— Is there any domestic know-how, or in-house developments, unique to the company that are not yet available to anyone else?

— Of course there are. For example, replacing foreign equipment with a domestic solution in horizontal well construction has allowed us to reduce costs exponentially. And we now plan to use a full range of domestic technological solutions at one of our wells. This includes a rotary steerable drilling system, making it possible to bend the bore hole to the appropriate angle, a geo-navigation system — which is to say, our eyes underground — and a geophysical logging system, making it possible to sound-out the construction of geological cross-sections.

— Digitisation, digital transformation — these are getting considerable attention at the moment. Have you calculated the real economic effect that implementing these technologies might deliver?

— The economic benefit of utilising digital technologies is generally believed to be between seven to 10 percent. For us, deliberate digitisation didn’t start one, two, or three years ago. This area has always been a very important part of our Technology Strategy, and today every stage — from early exploration to production — is covered by IT solutions developed by ourselves.

— Can you give any stereotypical ideas about the oil and gas industry that are very difficult to shake off?

— Once such stereotype, probably, is that oil and gas is an industry on its way out — one in which all the important stuff is in the past. That’s definitely not the case, certainly not in Russia. Demand for our products will only grow, in the foreseeable future, and as regards technological capability, it’s hard to find another industry working with the same volumes of data and making very important multi-billion investments in an environment of such high levels of uncertainty. This happens in the pretty early stages, when we first come into contact with an object that we won’t see directly, not even once, until we’ve drilled the first exploratory-appraisal well. Taking the right, economically viable decision in those circumstances is only possible thanks to an advanced ability in working with data — that’s our key skill.

We don’t drill the wells, and we don’t operate the machinery used in developing fields. That’s all done by service providers. But we put projects together in such a way as to make sure we obtain information on time, spend the optimum amount of money and time on this, and install infrastructure that’s going to be working for decades ahead.