For oil and gas companies hoping to strike and successfully develop massive hydrocarbon finds in Russia, adjusting plans for the political wildcard has become a requirement.

The outlook can appear sunny one day, and then actions of the powers that be can strike, bringing rainy days and clouding the future. Russia was dealt a blow when the U.S. and EU imposed sanctions that shut off the flow of energy technology and financial backing in response to Russia’s actions threatening Ukraine’s sovereignty and territorial integrity.

Despite a cease-fire and a peace deal struck between Ukraine and Russia, the EU—followed by the U.S. whose president said, “We have yet to see conclusive evidence that Russia has ceased its efforts to destabilize Ukraine,”—deepened the sanctions in September. The restrictions include prohibiting the export of goods, services and technology in support of E&P for Russian deepwater, Arctic offshore or shale projects to Gazprom, Gazprom Neft, Lukoil, Surgutneftegas and Rosneft. The mandate gave U.S. persons until Sept. 26 to “wind down applicable transactions.”

The situation is fluid with the potential for more fallout from what has been called Russia’s invasion into the post-Soviet state—or not if Russia complies with certain terms. But what remains unchanged is Russia’s enormous amount of hydrocarbon resources and the possibilities for more oil and gas discoveries onshore and offshore, from the Arctic to Siberia.

By 2020, Russia’s oil production is predicted to rise to about 565 million tons per year, up from about 491 million tons in 2007, most likely bound for the Far East and Western Europe, according to Energy Bloc Research. Likewise, gas production is expected to jump, climbing more than 100 Bcm (3.5 Tcf) to reach 760 Bcm (26 Tcf) per year by 2020. Data from the U.S. Energy Information Administration (EIA) showed Russia had 80 Bbbl of proven oil reserves and 51 Tcm (1,688 Tcf) of gas reserves as of Jan. 1, 2013.

However, in September Russia’s energy ministry said oil production will stabilize at about 525 million tons in 2015, up slightly from the anticipated year-end 2014 production of 525.3 million tons. Production could inch up to 526 million tons in 2017, according to the Russian government.

If E&P programs already underway progress as planned and prove successful, the outlook could change.

Areas capturing oil and gas companies’ attention include the Arctic, where Rosneft and partner ExxonMobil kicked off exploration drilling in the Kara Sea in August; Sakhalin Island, site of the Exxon Neftegas-operated three-field oil and gas project; and Eastern Siberia, including the Irkutsk region where Rosneft discovered three new hydrocarbon deposits in 2013. These areas could play a large role in the long run in addition to possible large reserves in the Russian sector of the Caspian Sea and undeveloped parts of Timan-Pechora; however, West Siberia—namely the Priobskoye and Samotlor fields—continue to provide the bulk of Russia’s oil production, the EIA said.

“We are seeing a dual push to lower permeability reservoirs—but not true unconventional reservoirs—such as the Tyumen and Achimov formations and more frontier regions onshore such as East Siberia,” Duncan Milligan, Russia upstream analyst for consultancy Wood Mackenzie, told E&P. “These will maintain a broadly flat rate of liquid production until 2020. The expected decline post-2020 is unlikely to be countered by conventional onshore regions, and this has led to the renewed push into the offshore Arctic and into tight oil production over the past two to three years.”

The Arctic

Covering 1,200 km (746 miles) with a 500-m (1,640-ft) hydrocarbon trap, Rosneft believes the Universitetskaya structure in the Arctic could contain more than 1.3 billion tons of oil equivalent. Already, a “total of some 30 structures were found in three East Prinovozemelskiy areas of the Kara Sea, and the entire resource base of the three areas is estimated at 87 billion barrels,” according to Rosneft, which also noted the Kara Sea oil province resources will be comparable to the resource base of Saudi Arabia.

Using North Atlantic Drilling’s West Alpha semisubmersible rig, Rosneft and ExxonMobil began work at the Universitetskaya-1 well in the Kara Sea. Rosneft said the well marks the farthest north rig for the Russian Federation. In preparation for the project, the rig was prepped for harsh arctic conditions. In addition to being equipped with a system that monitors ice condition, detects icebergs and tracks sea ice, Rosneft said an eight-anchor positioning system holds the rig in place and that most of the platform is outside the reach of waves.

“West Alpha was upgraded to improve the overall reliability of its main and supplementary equipment and for all systems to be ready for low temperatures, including, most importantly, life support and evacuation systems,” the Russian oil giant said. “To make sure West Alpha can operate safely in severe ice conditions, Rosneft and ExxonMobil developed a unique iceberg collision prevention plan. It even includes applying physical action to the ice.

“Should experts suspect a hummock or floe can damage the rig, special support vessels will tow it away to a safe distance. If physical action is impossible, the system will isolate the well in a way that is harmless for the environment, and the rig will transfer to a safer location,” Rosneft said. “The rig is equipped with two groups of blowout preventers and an enhanced subsea shut-in device.”

The project’s future, however, is uncertain given the latest round of sanctions. Moreover, having the right equipment in place checks one box, but the Russian Arctic presents additional challenges.

“Without the ice and remoteness, the Kara Sea would be a ‘simple’ geological development. However, the ice and 1,000-kilometer [621-mile] distance to port means that exploration well costs are extremely high,” Milligan said. “The Arctic is a very complicated logistical and environmental challenge, and successful ice management will be key for both exploration and development.

“Offshore developments with seasonal ice-cover exist already—in Sakhalin and Canada as well as the Arctic Prirazlomnoye platform, but all of these are much closer to existing infrastructure,” he continued. “Should several discoveries occur in the Arctic and operators decide to proceed with investment, it is likely that a large infrastructure building campaign would be needed. The Russian state acknowledges as much and is investing in things such as nuclear icebreakers, which will be key for safe Arctic development.”

Siberia

Another set of challenges and opportunities waits in Siberia, site of the Bazhenov Formation, which has been compared to the Bakken in the U.S. The Russian formation in the West Siberian Basin is believed to be one of the world’s largest shale oil and gas deposits, with the EIA estimating risked shale oil and gas in-place at 1,243 Bbbl and 58 Tcm (1,920 Tcf), respectively. The technically recoverable resource estimates are far lower at 74.6 Bbbl for oil and 9 Tcm (285 Tcf) for gas. However how much oil and gas can be recovered and at what cost remains to be seen.

Salym Petroleum Development, the joint venture company formed by Shell and Gazprom Neft, started drilling the first horizontal appraisal well earlier this year. The work comes as part of a pilot program that calls for drilling five multifracked horizontal appraisal wells from 2014 to 2015.

While exploration efforts are in the early stages for the Bazhenov, Milligan pointed out that the push for tight oil is already underway with the Tyumen Formation, a midway point between the traditional conventional reservoirs and the Bazhenov, and production here has doubled between 2010 and 2014. He noted similar growth seen in the Achimov and Ryabchik formations, which has countered the decline of Russia’s mature fields.

“For the Bazhenov, the challenge is to find a way to spot and drill sweet spots. The arrival of players like ExxonMobil (with experience from XTO), Statoil (Brigham) and Liberty Resources (large volume fractures in the Bakken) into West Siberia should help with the methodology in how to drill in unconventional reservoirs, but the tax environment and lack of high-end equipment at scale is challenging,” Milligan said. “The Russian government has the ability to reduce export duty, which accounts for around $55/bbl, but will probably only do so once more information about costs and returns is available.”

Research and consulting firm GlobalData said Russia’s finance ministry has begun to implement a shift of tax burden from export duty on oil to a revamped mineral extraction tax (MET). Export duty could drop from 59% to 55% by 2016.

“The base rate of the oil MET is set to increase from RUB495 ($13)/tonne to RUB559 ($15)/tonne. This base rate is multiplied by a number of other coefficients, including a price factor of around 10,” GlobalData said. “However, there have been reports of a more substantial change from 2015, which would reduce the oil export duty to 42% in 2015, 36% in 2016 and 30% in 2017 while at the same time increasing the base rate of the oil MET to RUB775 ($21)/tonne, RUB873 ($24)/tonne and RUB918 ($25)/tonne in each of these years, respectively.”

Considering most of the oil produced is exported, the change could improve the profitability of oilfield developments, according to Anna Belova, GlobalData’s lead upstream analyst for Russia. “The shift in tax burden would also increase the effectiveness of some incentives, such as regional MET holidays and reduced MET for depleted fields, heavy viscous crude, and unconventional oil,” she said.

But the firm noted that amendments could be made.

“The requirement for tax breaks to render certain projects profitable might be even more pronounced if the proposed MET increases are put in place,” said Will Scargill, fiscal analyst for GlobalData. “However, any new targeted incentives are only likely to be available for projects that have strategic importance for the government either from an economic or political perspective. In particular, special incentives for projects supplying China and other Asian markets may become more common.”

Then there are sanctions, which could impact some projects.

“The sanctions are focusing on the post-2020 pillars of Russia’s oil strategy, but the naming of companies and specific technologies has created a much higher degree of uncertainty,” Milligan explained. “For the technology sanctions, it will be the application of the sanctions that will dictate the ultimate impact they will have, and this hasn't been tested yet.”

Belova told Bloomberg that the sanctions “impose pain on Russia on a five- to 10-year horizon,” and that the exploration projects disrupted or delayed by the sanctions wouldn’t turn into productive oil fields for years. However, oilfield service companies, including Schlumberger, have already warned that the sanctions could impact their earnings.

Risky business

The biggest impact of the sanctions against Russia is to the investor climate, Victoria Brudenell, senior manager of business intelligence and investigations for the Salamanca Group, said during a phone interview. The sanctions tightened debt financing restrictions by lowering the maturity period for new debt issued by six Russian banks from 90 days to 30 days. To get needed funding, the sanctioned companies will look within Russia or go east and ask China.

After the U.S. imposed sanctions in July, which aim to end the conflict with Ukraine, Rosneft asked the state for up to $41 billion of aid. Since then, the country’s largest oil producer and Lukoil have received loans from OAO Promsvyazbank, Bloomberg reported.

“I think people are going to be pretty wary about investing in Russia, particularly in the oil and gas sector, but actually across Russia widely,” Brudenell said. “The foreign direct investments have fallen through the floor. I think it is expected to contract by 50% this year on last year, although last year was obviously a peak year because of the Rosneft-BP deal. But even still, I think that is the biggest issue.”

Speaking on other perceived political and operational risks for companies involved in Russia’s oil and gas sector, Brudenell said the issues of tenders can be nontransparent, corruption remains an issue and it’s often assumed that political connections are required; therefore, local partners are needed. “There is a lack of technical knowledge among the workforce in Russia,” she added. “Oil and gas contributes an enormous percentage of the GDP of the country, and therefore the state plays a heavy role in it, and that comes with its challenges.”

Her advice for companies considering operating in Russia is to “know who you are dealing with and not just who you are dealing with on paper,” trust and understand why partners are involved in projects, consider the requirements for technical expertise, have a good legal contract and framework within which to work and be aware of the level of risk.

International oil companies make a lot of money in Russia, but investors “have to be willing to accept a certain level of risk. The most important thing is to be well informed and to read beyond the headlines,” she continued.

Interest remains

Despite the operational risks, Russia stays on companies’ radars, and more than likely, international oil companies (IOCs) remain on Russia’s radars because it needs outside expertise to develop some of its hydrocarbon assets, whether it is EOR for mature fields or technology for frontier areas.

Russia is a place where companies, including supermajors, can chase conventional resource opportunities, Milligan said, noting others include Saudi Arabia, Iraq and Iran. “For this reason alone all major IOCs keep a watching brief on Russia even if they don't currently hold any investments.

“Due to abundant onshore resources Russia hasn't to date needed to develop offshore projects, and when it has it has often turned to IOCs,” Milligan said, using Sakhalin 1 and 2 as an example.

But as Russia turns focus to more costly developments such as in the Arctic and unconventional shale plays, outside funding and expertise will be crucial.

“The Arctic is a long-term play, and Rosneft will be keen to learn from the 50 years of offshore experience that the IOCs hold. This can be seen in the U.S. and Norwegian partnerships between Rosneft, ExxonMobil and Statoil, for example. The likely cost of developing any offshore Arctic discovery is also likely to be so great that having an IOC to help fund the development will be very advantageous.”

Several high-impact frontier areas remain onshore, Milligan added, noting each has challenges. For the Astrakhan region, the challenge is deep HP/HT reservoirs with sour gas. For the Gydan Peninsula, it’s remoteness and likely gas. For the southern part of East Siberia, it’s again remoteness along with limited infrastructure and long lead times to first production.

“Against this backdrop, exploration in the offshore Arctic and exploring tight reservoirs looks more attractive,” he continued. “Offshore the key areas are offshore Sakhalin and appraisal of the possibly super giant South Kirinskoye Field and in the Kara Sea—an extension of the prolific West Siberian Basin.”