Vadim Yakovlev, Deputy Chairman of the Management Board and First Deputy CEO, Gazprom Neft, and Chairman of the Board of Directors, NIS, answers our questions
— Vadim Vladislavovich, in the light of the OPEC+ deal, and the general market situation, will Gazprom Neft’s 2019 production levels be higher than in 2018?
— Assuming the same terms as the current agreement, which envisages OPEC+ countries cutting production, then, in that environment, we can confidently predict a two-percent increase in production growth in 2019. The exact figure, obviously, will depend on the precise terms of the deal in the second half of the year. But, even under that scenario, if it’s decided to cut production still further, Gazprom Neft will still be able to show growth.
— How does the company view the OPEC+ deal, as a whole — both for the market, and for Gazprom Neft itself?
— The OPEC+ deal is currently helping maintain prices at a level sufficient for us to fulfil both our current projects, and those in our future portfolio.
Maintaining stable oil prices in the long term is crucially important. The fact that a significant proportion of the leading oil producers have been able to come together to address this says much about the industry’s ability to cooperate and work towards achieving common goals. Indeed, predictable oil prices aren’t just about oil companies’ income — it’s also a question of guaranteeing we can meet demand for our products, in the future. It’s also about the stability of investment cycles, which, in our industry, can take five years, at a minimum. That is to say — in order to start production at a new license block within a few years, we have to invest resources today. When prices fluctuate across a wide range, companies start to spend less on exploring and developing new resources. This could ultimately impact the entire global economy if, at some point, we’re not able to meet demand due to having cut investment in the past.
— But one of the world’s three largest oil producers — the USA — hasn’t signed up to the deal. The USA has increased production by 2.7 million barrels since 2016, and has announced plans to increase it further. Which raises a reasonable question: will those volumes that OPEC+ countries are cutting back on be replaced by American production? And how far, really, is oil impacted by fundamental factors?
— The industry’s ability to make available volumes of oil in excess of demand, at the drop of a hat, is itself the result of fundamental factors which, in turn, impact pricing.
Added to which, the market is also impacted by other factors, which are hard to predict — the political situation, in individual countries and on the international arena; the attitude of market players, and so on. And attitudes, moreover, don’t just depend on hard facts, but also on expectations and assumptions. And you can only hold forth on that at a qualitative level. So a mathematical model that might be able to give market forecasts to a reasonable degree of certainty just doesn’t exist.
As regards the States’ actions, I’m in no doubt that balancing supply and demand — and, with that, stabilising prices and investment activity in the long term — are equally relevant to all market players. Only certain players are willing to take an active position, bringing their actions to bear on the market, and others either don’t want to do that, or are in no position to address that challenge due to there being too many players on the local market. So we see different behaviour. It might, initially, lead to a certain readjustment in market shares, but, in the long term, I’d like to stress, again, that I believe the parties’ activities to be rational and directed at stabilisation, in the long term.
110 million barrels and more
— Gazprom Neft had been planning to reach production of 100 million tonnes of oil equivalent (mtoe) per year by 2020. Given the current terms of the OPEC+ deal, is the company sticking with that plan, or does that now look unrealistic?
— That figure remains part of our current plans. We’ve taken the impact of the deal into account.
— You’ve adopted a strategy for development to 2030. Has the company also taken a view on global oil demand to the end of the next decade?
— We’ve assessed several scenarios, for our view on the outlook for the market forms the basis for that strategy. We’ve considered a range of forecasts, taking potential scenarios into account, in line with various price levels — from $40 per barrel to more than $90. There’s a model for the company’s development under each of these scenarios. The base option, moreover, stands at a level of about $60 per barrel. I say ‘about’ because this isn’t a constant — we’ve set down certain cycles that depend on how the global economy develops, and the factors impacting the oil price. Under that base scenario demand for oil will grow steadily — it surpassed the symbolic 100 million bpd mark at the end of last year. It needs to reach at least 110 million bpd by 2030.
— So you believe that growth is going to slow down in the 2020s? Demand is currently growing at about
— Nonetheless, I emphasise: ‘not less than’ 110 million. I am absolutely sure that the figure will be higher. But we have deliberately taken a pretty conservative scenario as a base.
— So that the investment decisions we take have a good margin of safety. I would point out that our base scenario takes into account such factors as an increasing proportion of renewables and electric vehicles.
— Whose forecasts are you relying on regarding the growth in electric vehicles?
— It’s a cumulative view. In any case, this won’t be a determining factor for the oil market coming up to 2030. Metrics like population growth and the state of the global economy are going to be more important.
Reserves are more challenging: production costs remain the same
— The quality of Gazprom Neft’s reserves is changing — the proportion of hard-to-recover reserves is increasing. How far are these likely to come to the fore, proportionally, by 2030?
— It’s certainly the case that hard-to-recover reserves are gradually increasing, proportionally, and non-traditional sources of oil are going to start playing a significant role, in the future. Geologists estimate the Bazhen Formation’s resources alone could reach
If we’re talking about hard-to-recover reserves in terms of our current production balance, then they account for about 30 percent; and in terms of the make-up of our resource-base — about 40 percent. Several years ago we started working on low-permeability and thin-bed strata; today we are increasingly moving towards blocks on field peripheries. One such project involves bringing the peripheral zone of the Priobskoye field into production, where permeability can be measured in terms of tenths or even hundredths of millidarcies,* although even two or three decades ago this would have been measured in terms of dozens — or even hundreds — of units. Which is to say — the quality of reserves has deteriorated hundred-fold.
— And the Achimovsky deposits?
— We’re placing a quite substantial bet on this reserves category. Open acreage is, already, out of light oil, so I think, in the long term, we’re going to have to take much longer bets. We have had to put our strategic portfolio together from options that don’t offer a
— Oil production costs are increasing, worldwide. I would think they’re likely to increase for you, too. What level do you expect these to be at, by 2030?
— Our operational production costs are currently running, on average, at about RUB2,100 per tonne. That’s quite low compared to other regions, worldwide. I should stress, this means operational costs, once basic infrastructure has been put in place. We think this figure is likely to increase in line with inflation up to 2030.
—So costs, in fact, will remain at current levels?
Yes. On the one hand, reserves are becoming ever more challenging. On the other, thanks to the fact that we’ve increased production rapidly in recent years, we have many new projects in our portfolio where production costs are even lower. Added to which, efficiency improvements — using cutting-edge technologies — have an impact on operating costs.
— But capital costs are going to go up, all the same.
— If we’re talking about remote fields, about using the most complex technological solutions — undoubtedly. But this is taken into account under the current tax system.
— The Novoportovskoye project is one of those given to Gazprom Neft by its parent company. Are you going to be getting other projects from Gazprom, in the foreseeable future?
— We are responsible for implementing the Gazprom Group’s oil strategy — that’s where our mission starts and ends. Our growth has been based on developing assets received from Gazprom: Novy Port, Prirazlomnoye, and the eastern block of the Orenburg field.
When these assets were transferred to us production was only undertaken in Orenburg, and altogether totalled about 530,000 tonnes per year. Today these three projects are producing about 12 million tonnes of oil every year.
Arktikgas, which we’re developing with NOVATEK, was also given to us by Gazprom. Arktikgas will be producing 26.4 bcm of gas this year, and about 8.7 mt of condensate and oil. We’re working at the Chayandinskoye oil and gas condensate field in eastern Siberia. We’re currently in the process of developing the Tazovskoye field, Pestsovoye oil-rim reservoirs and the En-Yakhinskoye field in the Yamalo-Nenets Autonomous Okrug. As regards oil-rim reservoirs — these were under blanket exploration and production licenses, and so weren’t transferred to us — we’re working under a risk-based operator agreement. That is to say — all investments are undertaken at our own risk, but the main income from the project will also be generated by us as the investor.
— How are gas projects integrated into the company’s production structure? And how are these going to be implemented in Yamal?
— We look at all options for productive gas utilisation, on every project — taking gas transportation infrastructure, market accessibility and so on into account. We’ve found various solutions, in various regions. In Orenburg we’re delivering gas through Gazprom Dobycha Orenburg’s infrastructure.
We’ve built a gas processing facility in conjunction with SIBUR At Priobskoye, and we’re supplying associated petroleum gas (APG) to SIBUR facilities in the Noyabrsk region.
Added to which, the further north we go, the more we come up against multicomponent deposits, and the more the gas component increases. And while oil production is our core business, we have to address the issues of developing both the oil and gas elements, holistically. At the Novoportovskoye field, for example, gas is injected directly into the strata — thus maintaining reservoir pressure, delivering more oil and extending useful well life. 17 million cubic metres of gas is injected every day — the largest gas utilisation project of its kind in Russia. Concurrently with this we’re working on installing a gas pipeline in Yamburg, because significant gas volumes at Novy Port make that decision necessary. The possibility of bringing reserves at other blocks in that area into production was also considered in determining technical parameters, in order to guarantee capacity load and project viability. Capacity is expected to reach up to 20 billion cubic metres of gas this year.
— You’re not considering the possibility of building a LNG plant?
— Seriously, that possibility has never been discussed. We have no such plans.
— The company is under sanctions. How have your technical, technological and scientific resources and strategy changed, vis-à-vis exploration and production?
— If we’re talking about the impact of sanctions, then we haven’t had to stop a single project because of this. They’ve had an impact only in terms of selecting potential technological partners. For example, the Bazhen project turned out to be closed to western companies. We are now working with Russian businesses, with which we are developing a complex of 20 technologies in drilling, well finishing, strata stimulation, and more. As part of this collaboration we have, together with MIPT (the Moscow Institute of Physics and Technology), developed the first domestic fracking-simulation programme at the Bazhen Formation. Our simulator is superior to existing commercial products, in contrast to which it can calculate variations in the geo-mechanical properties of strata, taking induced fissures into account — that is, their interaction with and impacts on each other. This is a unique product for the market. Our plans are that by 2025 we won’t just have chosen the most effective technologies for developing the Bazhen Formation, but will have gone through the training stage, and will be reducing the costs of all solutions in order to move on to viable production.
— Even under current prices?
— Even under current prices. We’re aiming for production at 2.5 million tonnes per year by 2025. We drilled 10 pilot-production wells in 2018. We obtained a commercial inflow at every one of these — each with its own specific construction, with its own mix of technologies. We drilled one well with a horizontal shaft of 1,000 metres, and conducted
— What other technology projects could be considered ground-breaking?
— Of course, the challenge of technological development isn’t limited to the Bazhen Formation alone. I mean, take the Achimovsky deposits, for one: abnormally high reservoir pressure, low permeability and extremely high temperatures. The scale of this project is massive. We built the first ever digital geological model of the entire Achimovsky formation at our Science and Technology Centre last year. The most promising blocks became immediately apparent — first and foremost in the north of the Yamalo-Nenets Autonomous Okrug. The most significant reserves are concentrated in Gazprom’s Yamburg field. It’s light oil, in composition. Reserves in place stand at billions of tonnes. Generally, our reserves drive the company’s technological development. And in technological development we are driven by the need to outstrip import.
— What do you mean by “to outstrip import”?
— We are trying to develop solutions that don’t just substitute, but actually surpass international alternatives in terms of their effectiveness. Very often, the world just doesn’t have any such alternatives yet. We are, today, successfully implementing projects with more than 100 Russian and international manufacturers: new digital solutions, specifically, are being developed in partnership with Yandex, IBM, the Mail.RU group and others. We’re pursuing developments in artificial intelligence (AI), for example.
AI in oil production
— AI in oil production — what for?
— We work with massive volumes of data. Digital technologies and artificial intelligence allow us to increase speed and efficiency in processing that data. In finding new sources for adding value. I’ll give you an example. A digital model was made of the Priobskoye field, covering the entire system — strata, wells, and oil collection, processing and transportation. The total well stock stands at 3,500. The AI system processes 3.5 million signals per second. No traditional data processing system could ever do that. Wells at a field operate periodically — when some start, others stop. AI has identified optimum system parameters and worked out a regime to exploit the potential of field and infrastructure as far as possible. The well stock, which was previously managed manually, now runs on autopilot. Production is up 1.5 percent, solely thanks to this. And the economic benefit is up to RUB1 billion per year.
We’ve set up a Project Management Centre — an integrated digital and organisational forum for implementing major projects.
According to our estimates, organisational and digital optimisation will cut average lead times from 12 to 7 years in total, and from 6 to 3 years for “first oil”. In terms of return on investment, this is a genuine breakthrough — until quite recently these sorts of lead times were considered, in principle, unrealistic. And that’s just a few examples.
10 years in Serbia
— This year marks an anniversary — it’s 10 years since the acquisition of Naftna Industrija Srbije (NIS). How effective has your investment turned out to be?
— This is a highly successful project. At the time of the acquisition NIS was seriously unprofitable, and production volumes were down. Within two years we’d taken the company into profit, and, thus far, financial results just keep going up. Since 2013 NIS has regularly paid its shareholders dividends in the order of 25 percent — in line with international best practice — with shareholders receiving more than EUR400 million in total cumulative dividends since 2013. But what matters is not just the immediate return, but NIS’ added value and the return in the future. This company is now Serbia’s biggest taxpayer, paying about EUR1 billion into the budget, every year. NIS’ activities aren’t just expanding in Serbia — the company has, for us, become a springboard for developing throughout the entire Balkans region — in Bulgaria, Romania, and Bosnia and Herzegovina.
— How are relations with the Serbian leadership coming along?
— Our main means of engagement is through the NIS Board of Directors. Absolutely all decisions, throughout our work, have been taken by consensus, and with all mutual interests taken into account: ours, and that of the other key shareholder — the Serbian government.
— How does NIS fit into the Gazprom Neft production chain now?
— NIS buys our oil, and our base oils. Serbia was the first country in which we started selling our high-performance G-Drive 100 fuel; the company also performs certain tasks through its Science and Technology Centre.
— Are you going to move into any other international projects in the near future?
— We’re looking at the possibility of expanding our activities in the Middle East.