Russia’s oil production had remained stable at around 11.2 million bbl/d, consistent with OPEC+ production cuts, now extended through 2019. In the longer term, the country will struggle to keep oil production stable, primarily due to lack of sanctioning seen over the last years. This article assesses the status and outlook for Russia’s E&P, illustrated by the three key drivers: production, economics of new projects and capital investments.
Figure 1 shows the total oil (crude and condensate) production for Russia from 2010 to 2030 split by the year of sanctioning. Last year, oil production stood at 11.16 million bbl/d. In December 2018, as part of the OPEC+ agreement, Russia agreed to cut production by 2% relative to October 2018 levels. On a country level, these production cuts were accomplished as a result of the Druzhba pipeline contamination and overall corresponded to approximately 228,000 bbl/d in cuts relative to October 2018 levels. In a July 2019 meeting, OPEC+ had agreed to extend the production cuts for an additional nine months. Hence, we expect Russian oil production to average 11.2 million bbl/d this year, and remain around this level over the next two years. In the long term, Russia will struggle to keep oil production stable and we see the need for new discoveries to be actively developed to offset mature field decline in the region. As illustrated in Figure 1, during 2016-2020 Russia sanctioned significantly less volumes than in the preceding years. Fields that were sanctioned during 2011-2015, for instance, contributed nearly 2.3 million bbl/d at peak. At the same time, fields expected to have an FID in 2016-2020 contribute only 0.55 million bbl/d at peak. This is a significant reduction in new volumes to be delivered to the market, which largely explains the oil production decline forecasted. Active development of new fields should thus become a priority for Russian producers over the next years to avoid notable production decline. Important projects anticipated to be sanctioned over the next five years include the Kuyumba field (phases 2 and 3), West Messoyakha, as well as the Neptune and Triton fields in the Ayashsky license block. Last year, several notable fields came on stream, including the Rosneft-operated Tagulskoye, Russkoye and Srednebotuobinskoye phase 2, the second phase of Lukoil’s Vladimir Filanovsky, as well as Novoportovskoye phase 2 (Gazprom Neft-operated) and Novatek’s Odoptu stage 2 offshore Sakhalin.
Figure 2 shows recoverable oil resources and breakeven prices as of the FID date for top unsanctioned oil fields in Russia expected to come on stream before 2030. The fields are further classified according to the operator and region. The top two oil companies in Russia - Rosneft and Gazprom Neft - hold the largest discoveries that are expected to play an important role in production dynamics in the country. Through a joint venture (Slavneft), together they also own a large phased Kuyumbinskoye development, early phase of which is already producing. While a large part of current oil production originates from mature Western Siberia, a vast majority of discovered and undeveloped fields is located in Eastern Siberia, the region that will see more active development in the future. Among the largest fields in the region, Rosneft operated Savostyanov holds over 700 million bbl of oil and its breakeven oil price is currently estimated at around $54 per bbl. Since infrastructure in Eastern Siberia is not yet as developed as in Western Siberia, the costs associated with field developments located further away from already producing fields are rather high, which pushes breakevens up. Consistent with that, Savostyanov is forecasted to come on stream closer to 2028, after the fields with higher commerciality are developed. Phase two of Yurubcheno-Tokhomskoye, for instance, has a breakeven price of below $25 per bbl since large part of infrastructure is already in place. It is thus anticipated that the field will come on stream within next five to six years. Despite Western Siberia being largely considered a mature region, there are still important discoveries to be developed. PK1 layer of Komsomolskoye North is estimated to hold nearly 400 million boe of oil and will be co-developed with Equinor with start-up currently estimated towards 2024. Finally, there are also significant resources held offshore. Gazprom Neft is operating Neptune and Triton fields discovered in 2017 and 2018, respectively, in the Sea of Okhotsk. Neptune holds over 600 million boe of oil and is planned to be operational by 2027, while Triton is seen to follow soon after with additional 200 million of oil to be developed.
Figure 3 shows the capital spending on oil fields in Russia from 2010 to 2025. Capital expenditures reached a high of $42 billion in 2013, falling sharply to around $30 billion in 2015 and further decreasing to $27 billion by 2016. The fall in the oil price has had an effect on the ruble; and thus spending in dollar terms has fallen substantially. The investments in ruble terms have remained high even during the periods of very low oil price, since most of the cost in Russia is spent locally. The capital investments in dollar terms increased by 24% in 2017, supported by recovering oil prices and a slight appreciation of the ruble. Spending is expected to remain stable at around $30 billion this year, and higher investments are not anticipated before 2023-2024. The main driver behind the growth in capital expenditures post 2022 are investments in not yet sanctioned discoveries, including Sanarskoye, Kuyumbinskoye phase 3, Severo-Komsomolskoye, and Neptune, Gazprom Neft’s 2017 discovery in the Ayashsky block.
US shale production has seen continuous growth since the low in 2016, and is expected to keep growing in the medium term, albeit at a slower rate. By the end of 2019, light oil supply in the US is forecasted to reach 9 million bbl/d. The Permian Basin will be the key contributor to the oil production growth going forward, with stable volumes expected from the more mature shale plays that were leading the growth prior to the oil price crash in 2014. Despite the slowdown in spending seen this year, as companies strive to spend within cash flow, and the corresponding stable drilling and completion activity trend, total US shale volumes are expected to reach 32 million boe/d (12.4 million bbl/d light oil) by 2023.