Russia’s oil production increased to a five-month high in January following an agreement with the Opec+ alliance to exclude condensate from its quota.
The nation pumped 47.72mn tonnes of crude and condensate – a light oil extracted from natural gas – last month, Interfax reported, citing preliminary data from the Energy Ministry’s CDU-TEK unit. The figure, which may be rounded, equates to about 11.28mn barrels a day on average, based on the standard 7.33 barrels-per-tonne conversion ratio.
The CDU-TEK data usually doesn’t provide a separate figure for crude production, so it can’t be used to gauge Russia’s compliance with promised output cuts. In December, the country successfully lobbied the Organisation of Petroleum Exporting Countries and its allies to exclude condensate from its quota.
Energy Minister Alexander Novak has insisted the exclusion isn’t a loophole, and that Russia will be transparent about its oil production. Last month, the ministry published December figures that showed how Russia may disclose its compliance. While the statement was less detailed than the CDU-TEK data, it split output cuts into crude and condensate, compared with the respective October 2018 baselines.
Russia has pledged to cut its crude-only output by 298,000 barrels a day this quarter, from a baseline of 10.626mn barrels a day. The nation was not far from meeting that target in December, the Energy Ministry said, reporting crude-only cuts of 234,000 barrels a day.
Russia largely failed to meet its obligations in 2019 under the previous Opec+ deal. It attributed that failure to challenging weather and geological conditions in winter, the temporary shutdown of the Druzhba oil pipeline and growing condensate output at gas projects. Russia’s main gas producers Novatek PJSC and Gazprom PJSC have been bringing new fields online and expanding existing projects to ramp up exports to markets in Europe and Asia.

LONDON – BP has pulled out of Iraq’s giant Kirkuk oilfield after its $100 million exploration contract expired with no agreement on the field’s expansion, dealing a fresh blow to Iraq’s hopes to increase its oil output, three sources told Reuters.

The move came as Western energy companies are reassessing operations in Iraq amid political turmoil following months of anti-government protests and a flare-up in tensions between the United States and Iran in the country.

BP informed Iraqi authorities in December that it was removing its staff from the oilfield in the north of the country after its 2013 service contract expired at the end of 2019, the sources familiar with the matter said.

A senior source at Iraq’s North Oil Company (NOC), which oversees the Kirkuk operations, confirmed BP’s withdrawal.

“The results of its field study for Kirkuk oilfield development have been handed over to the North Oil Company and unfortunately it was below expectations… at least for us,” the official said.

“It’s very obvious study results were not encouraging for BP to extend its operations,” he added.

The Iraqi government did not reply to a request for comment.

BP confirmed it had completed field work and studies and said it gave its recommendations for the development of the field to the NOC. The London-based company did not comment on staff movements.

“In 2013, BP signed a letter of intent with the North Oil Company of the Iraqi Ministry of Oil to support field activity studies in Kirkuk. As planned, in December 2019 BP completed field work, studies and recommendations,” it said.

Another senior NOC engineer said BP staff members left their laptops with the NOC after completing the survey and technical study of the field.

Iraq was hoping BP would help it triple output from the field to 1 million barrels per day (bpd) — more than one-fifth of Iraq’s current production and 1% of global output.

BP’s contract was put on hold in 2014 when the Iraqi Army collapsed in the face of Islamic State’s sweeping advance in northern and western Iraq, allowing the Kurdish regional government (KRG) to take control of the Kirkuk region.

Baghdad regained full control of the deposit from the regional government in 2017 after a failed Kurdish independence referendum, at which point BP resumed its studies on the field.

Kirkuk, where oil was discovered in 1927, is the birthplace of Iraq’s oil industry. BP and Iraq’s Oil Ministry signed in 2013 a letter of intent to study the development of the field with a planned spending of $100 million.

BP’s work included a 3D seismic study of the field’s reservoir to expand on the existing 2D data.

Kirkuk is estimated to contain about 9 billion barrels of recoverable oil, BP said.

Most of Iraq’s crude is produced from areas managed by the central government of Baghdad, in the south, and exported from southern ports on the Gulf. The KRG exports about 300,000 bpd of crude from northern Iraq through a pipeline across Turkey.

Oil majors are at the sharp end of the climate debate and face a bewildering balancing act to secure their futures.

It’s a Catch-22 situation: to meet ambitious emissions targets by investing in low-carbon technologies, they will have to rely on revenue from expanding their businesses in oil and gas, for which there is still growing global demand.

On one hand, they must satisfy the big investors who are rewarding companies with progressive climate policies and dumping heavy polluters; yet on the other, they can’t risk cutting the generous dividends that keep shareholders sweet.

How energy companies navigate this maze could determine the winners and losers in a lower-carbon future, and help govern whether the world can rein in warming. So no pressure, then.

The confusion has been thrown into stark relief this week at the World Economic Forum in the Swiss ski resort of Davos, where oil majors, state oil giants and ministers have been debating behind closed doors in their biggest gathering of the year.

While climate activists, notably Greta Thunberg, have called for all fossil fuel production to be halted to avert catastrophe, U.S President Donald Trump has decried “prophets of doom” and hailed the economic importance of oil and gas.

“It feels like we are at the epicentre of this debate. We sit right there between energy needs and climate change,” said Al Cook, executive vice-president of Norway’s energy giant Equinor.

“If you listen to Davos speeches, you’ve got some people who say only economic growth and energy matter. Others ask to stop oil and gas immediately. We need to find a way to balance this but the challenge is that you cannot always be popular with either side,” Cook told Reuters.

CLEAN ENERGY: FRACTION OF CAPEX
Repsol is at the vanguard of an industry climate drive, announcing this year that it plans to become carbon neutral by 2050. As a result, Norway’s wealth fund has doubled its stake in the Spanish energy firm.

Equinor has meanwhile launched a target to reduce emissions to near zero in Norwegian offshore production by 2050, and is co-investing in a $10 billion wind farm in Britain, the world’s largest.

French oil major Total this year announced investments into one of the world’s largest solar power plants, in Qatar. It also plans to open 20,000 power charging points in the Netherlands and invest in planting millions of trees in Peru.

Europe’s top oil firms have all set carbon reduction goals of various breadth. Shell has set out an “ambition” to halve “Scope 3” emissions by 2050 from fuels and products sold to customers rather than from its own operations.

Reuters reported this week that BP is also looking to significantly broaden its targets.

Companies might tout green credentials to satisfy sustainable investors and activists, but how can they pay the bill?

Fatih Birol the head of the International Energy Agency, the energy watchdog for industrialised nations, said the reality was that industry investments in clean energy represented a small fraction of their spending.

“Last year only 1% of total capex went into clean technologies. But those investments will grow as companies have to balance their short-term profit goals with long-term social licence,” he said.

“Some companies won’t need to borrow more, some companies may need to borrow more, but no company will stay unaffected by the energy transition.”

He said the industry would focus in coming years on reducing methane emissions from their own operations, which constitute 15% of all global greenhouse emissions.

“This part can be done relatively inexpensively,” he added. “The more expensive part will include carbon capture and storage, offshore wind and increased use of hydrogen.”

THE TRUMP EFFECT
Another major challenge to climate action is a lack of a global consensus.

In the United States, where Trump is encouraging oil and gas production and has exited the Paris climate deal, oil majors lag their European rivals on emissions goals. Chevron has set limited reduction targets while ExxonMobil has no targets.

A U.S. energy boom has helped make the country one of the world’s biggest gas flarers.

“No-one has been able to fill the previous political leadership role on climate change that was played by the U.S. in the past,” said Majid Jafar, chief executive of UAE-based Crescent Petroleum.

Jafar argues that if the world replaced all coal with gas, it would achieve the Paris climate target of by keeping global warming to well below 2 degrees Celsius. The problem is that the biggest coal consumers, China and India, will not be able to do that for years if not decades, he said.

“The efforts of the West will be futile without bringing on board Asia and Africa, which are driving the growth in energy demand and emissions,” he added.

Richard Herrington, head of earth sciences at London’s National History Museum also said a speedy energy transition may simply be impossible.

“If the UK were to turn tomorrow all of its cars into electric ones, we would need twice the world annual cobalt and half of annual copper production,” he said. “You can imagine what happens if you scale it up to the whole world.”
Source: Reuters (Reporting by Dmitry Zhdannikov; Editing by Pravin Char)

LONDON (Bloomberg) – OPEC’s latest forecasts suggested a weaker outlook for global oil markets this year as surging supplies from competitors from Norway to Guyana threaten the group’s efforts to defend crude prices.

The organization and its allies — which together account for about half the world’s oil output — are embarking on a fresh round of production cuts as another year of booming rival supplies threatens to unleash a new glut. OPEC’s latest monthly report shows their challenge extends far beyond the shale patch of Texas and North Dakota.

The Organization of Petroleum Exporting Countries boosted forecasts for growth in output from non-members in 2020 by 180,000 barrels a day to 2.35 million a day, as offshore projects once seen unfeasible in an era of lower oil prices take off. While the outlook for the U.S. was lowered, America will still account for almost two thirds of the new output.

Although the group raised estimates for world demand, rival supplies will grow about twice as fast, potentially derailing the coalition’s strategy to maintain oil revenues for its members. Crude futures are trading near $64 a barrel in London, close to the lowest in a month, even after flaring tensions between the U.S. and Iran rekindled fears of a major supply disruption.

OPEC and allies including Russia and Kazakhstan are deepening production cutbacks made last year in order to remove excess global inventories, pledging overall curbs of about 2.1 million barrels a day. This month’s report suggests those measures should be sufficient to deplete stockpiles during the first quarter, but that a surplus will probably return in the second.

Saudi Arabia, the group’s biggest member and de facto leader, rushed to implement almost all of the additional reductions pledged before the new agreement even took effect, the report showed. The kingdom reduced output by 111,000 barrels a day in December to 9.762 million a day.

As a result, the organization’s total production fell to 29.44 million a day last month. If other nations implement just part of their pledged reductions, output should be near the average of 29.19 million a day needed in the first quarter. However, even full compliance won’t prevent stocks building up in the second quarter, when the requirement for OPEC’s crude drops to 28.56 million a day.

The full alliance is due to meet in early March, when the agreement is due to expire, to decide whether to continue with the strategy.

LONDON (Reuters) – Long-term expectations about oil prices remain firmly anchored around $65-70 per barrel, according to the latest annual survey of energy professionals conducted by Reuters.

Plentiful supplies from U.S. shale plays and other sources outside the Organization of the Petroleum Exporting Countries are expected to keep prices close to their recent range for the indefinite future.

Fears about peaking oil supplies, common ten years ago, have disappeared; now there are some indications that expectations about peaking oil demand are taking hold.

Brent is forecast to average $65 per barrel in each of the next five years based on the median, or $67 this year rising slightly to $69 by 2024 based on the mean.

Most forecasters expect average prices to remain between $60 and $75 per barrel in each of the next five years, with only a very small number expecting them to dip below $50 or rise above $90.

The results are based on a questionnaire sent to over 9,000 energy market professionals, with responses received from 950 between Jan. 8 and Jan. 11 (tmsnrt.rs/2FNjC5J).

Price forecasts are very close to last year’s survey and previous years, though in most cases the average has fallen by $1 or $2.

In earlier surveys, there was some slight upward drift in price expectations for the out years, but there is no sign of that this year.

Most respondents seem convinced there will be enough oil to meet conceivable demand at around $65 per barrel in the medium term.

Fewer than 5% thought oil prices would average $100 or more in 2024, prices that would signal pressure on production, which were once common between 2011 and 2014.

In contrast, nearly 16% of respondents thought prices would average less than $50, a possible a sign of softening consumption and market saturation as part of the transition away from an oil-based transportation system.

OIL INDUSTRY INSIDERS

Among survey respondents, 26% are involved directly in oil and gas production (exploration, drilling, production, refining, marketing and field services).

Most of the rest are involved in banking and finance (19%), research (11%), professional services (7%), hedge funds (7%), other energy industries (5%) and physical commodity trading (5%).

The results from respondents involved directly in the oil and gas industry were very similar to those in other sectors.

Oil and gas insiders and those outside the industry have more or less the same views about prices in 2020.

Insiders are marginally more bullish than outsiders for later years, perhaps predicting higher prices will be needed to ensure production growth, but the difference is just $2 per barrel in 2022, rising to less than $4 in 2024.

EXPECTATIONS ANCHOR

Last year’s survey predicted Brent prices would average $63 per barrel in 2019, which proved remarkably close to the actual outturn of $64, based on daily closing prices.

In fact, the survey has been highly accurate since its inception in 2016, with the possible exception of 2018, when prices climbed a bit more than expected.

The main reason for the miss was probably the unexpected severity of U.S. sanctions on Iran, coupled with Saudi Arabia’s restrictive output policy and an acceleration in global growth.

In this year’s survey, as with previous versions, respondents exhibit more certainty about prices this year and next compared with the out-years, which is natural given that uncertainty tends to increase over longer time horizons.

Responses for 2020-2021 are tightly clustered, while expectations for 2023-24 exhibit more variation. Even so, very few respondents expect average prices to fall below $50 or rise above $90 at any point in the next five years.

Response clustering has been increasing in recent surveys, suggesting the anchoring of long-term expectations around the $65-70 per barrel level is becoming stronger.

The longer prices trade around the $65-70 level, with production and consumption roughly in balance, the more expectations are becoming cemented around this level.

Over the last 27 months, since the start of November 2017, Brent prices have closed between $60 and $75 per barrel on 74% of all trading days, with just 10% of closes below this level and $16% above it.

Overall, most respondents expect the oil market to remain comfortably supplied in the foreseeable future, with prices oscillating around the current level and relatively moderate volatility.

The world’s most-ambitious oil drillers are opening a new exploration frontier at perhaps the worst possible time.
With a slew of large discoveries off South America’s northeast coast, Exxon Mobil Corp, Hess Corp, Apache Corp and their partners are set to unleash new supplies onto global markets increasingly awash in crude.
Apache is the latest American driller to surprise investors with a significant discovery in coastal waters near the Suriname-Guyana border. The Houston-based explorer may have tipped its hand that something big was coming when it brought France’s Total SA on board as a partner in the endeavour just weeks before Tuesday’s announcement. Nonetheless, Apache’s stock surged 27% for the biggest one-day advance in at least 40 years.
“It’s pretty remarkable when you think about the larger landscape in which these new supplies will come online,” said Gianna Bern, a former BP Plc oil trader who teaches finance at the University of Notre Dame. “At the same time, Apache and companies like that tend to assume very low prices before development so that the economics will be favorable” regardless of market fluctuations.
Although it could be years before the Suriname find comes online, the discovery comes at a time when traders already are bracing for the biggest influx from non-Opec producers in at least 15 years, according to JBC Energy.
The rally in Apache shares is a vote of confidence from holders that chief executive officer John Christmann’s management team can pump that oil so cheaply that it will turn a profit even if crude collapses to $30 or $25 a barrel, said Bern, author of Investing in Energy: A Primer on the Economic of the Energy Industry.
Hess enjoyed just such a boom last year when investors boosted the shares 65% because of the oil producer’s role as a junior partner in Exxon Mobil Corp’s staggering discoveries off Guyana.
Guyana and Suriname are not alone. New supplies are flowing, or will be shortly, from new wells in Norway, Canada, Mexico, Brazil and Colombia, Bern said. Brazil alone is forecast to add 200,000 to 300,000 barrels of daily supply this year, and only US shale is expected to expand at a faster rate, said Fernando Valle, an analyst at Bloomberg Intelligence.
Outside the Organization of Petroleum Exporting Countries, output of crude and byproducts known as gas liquids will increase by 2mn barrels a day this year, swamping the 1.2mn-barrel growth forecast, according to IHS Markit.
Brazil and Guyana alone are set to add more than 400,000 barrels of combined daily supplies to the market this year, a volume that would offset most of the auxiliary cuts agreed to by Opec and its allies in late 2019, said Stephen Beck, the Houston-based senior director of upstream at Stratas Advisors.
“We’ve been in a situation where too much supply is chasing too little demand since 2013,” said Jim Burkhard, vice president and head of oil market at IHS. “2020 is shaping up to be the same way.”
The wild card, though, is what transpires with Iraqi production in the aftermath of the US assassination of a top Iranian general, Burkhard said.
As Opec’s second-largest producer, any disruption to Iraqi output could upend markets. Crude futures surged above $70 a barrel in London on Monday on concern the attack would spark a wider conflict. Still, they remain almost 10% off the 2019 high touched in April.
In past decades, new discoveries weren’t viewed as an imminent threat to the supply-demand balance because they took upwards of a decade to bring into production. But technological advances now allow explorers to turn discoveries into producing assets in half that span, upsetting old maxims about the time horizons for new supplies.
Relative to shale fields or conventional onshore wells, offshore projects tend to be more resilient to volatile price movements because once the initial construction is finished, operational costs are so slim that “oil would have to get under $10 a barrel before they’d shut them in,” said Jim Krane, a fellow at Rice University‘s Center for Energy Studies in Houston.
“Once the ball is rolling, you plow full steam ahead. Damn the oil price,” Krane said. “Clearly that’s what’s happening in Guyana.”

Just shy of $100 a barrel — that’s the cost of a type of crude that’s become prized thanks to the scramble for cleaner-burning fuels.

Australia’s Santos Ltd. this week sold a cargo of March-loading Pyrenees, a dense and low-sulfur oil, at a premium of about $31 a barrel over Dated Brent, according to traders who took part in the tender. That’s the equivalent to just under $100 a barrel given that the global benchmark is trading at about $65.

Demand for so-called heavy-sweet oil like Pyrenees has surged in recent months due to cleaner global ship-fuel standards, known as IMO 2020, which took effect Jan. 1. The new rules have boosted the value of these crudes that are low in sulfur and also viscous, which makes them better for marine engines. Low-sulfur marine fuel, another IMO compliant type of oil, cost about $640 a ton this week in Singapore, the equivalent of about $95 a barrel.

Santos had sought a target price of $32 a barrel or more over Dated Brent, according to traders. The company has a minority stake in the Pyrenees project, which it acquired through its 2018 purchase of Quadrant Energy.

“New IMO 2020 environmental regulations for shipping bunker fuel are driving the low-sulfur fuel oil market,” a Santos spokeswoman said in an emailed statement. “Heavy sweet crudes like those from our Van Gogh and Pyrenees fields are well suited for fuel oil blending to meet the new environmental requirements and are currently in very high demand.”

Pyrenees is also particularly valued because of its relative scarcity, with production of about 15,000 barrels a day pumped from fields off Western Australia, according to BHP Group, the majority owner and operator. A cargo to load this month was sold in November at more than $17 a barrel over Dated Brent. Another Australian heavy-sweet crude, Van Gogh, sold at a premium of as high as $19 to Dated Brent in December.

With Hungary, Bulgaria and Serbia to depend on TurkStream, Turkey’s importance to increase in terms of energy security

Yunus Furuncu completed his bachelor’s degree and master’s degree at the Vienna University of Economics and his Ph.D. at Duzce University and works as a researcher at the energy desk of the Foundation for Political, Economic and Social Research (SETA).

ISTANBUL

The inauguration of the TurkStream natural gas pipeline project, which will begin carrying natural gas from Russia to Europe via Turkey on Jan. 8, 2020, is considered a further step in Turkish and Russian relations in terms of energy.

The project, which has two lines, each of which has a carrying capacity of 15.75 billion cubic meters of natural gas, is particularly important for southern European countries. It will mark the first time that Russian natural gas will reach Europe via Turkey. The TurkStream project transfers natural gas directly to Turkey, which the country takes from the West Line, and it means a new route for European countries. Thus, Turkey has strengthened its position as a country that contributes to the energy security of Europe.

Turkey’s energy security increasing

Turkey’s claim of being an energy hub has been strengthened by the TurkStream project, which enables the country to directly take the natural gas coming from the West Line. TurkStream, which will be operated by a company established by BOTAS and Gazprom, is an important route for meeting the natural gas needs of Europe. The project, which increases the mutual dependency between Ankara and Moscow, positively contributes to the advancement of cooperation for future relations between the countries. Thus, TurkStream is significant for revealing that energy sources strengthen cooperation and ensure economic benefits rather than causing conflicts.

The West Line, one of the routes coming from Russia, reaches Turkey by passing through Ukraine and Bulgaria. Political and economic tensions between Russia and Ukraine sometimes lead to an interruption of natural gas transmission from the West Line to Turkey.

This situation poses a great risk for the Turkish economy. Transmitting the annual 14 billion cubic meters of gas from the West Line to Turkey over the first line of TurkStream, without changing terms and conditions of the existing agreements, means reducing this risk. Thus, gas will be directly transmitted from Russia to Turkey without the need for intermediate countries, and the problem of being exposed to potential interruptions caused by third parties will be eliminated. As a result, Turkey’s energy security has increased with this project.

Since the pipelines in Ukraine have reached the end of their service life, they must be repaired and replaced. Some 20,000 kilometers of a total 33,000 kilometers of transmission pipelines are more than 33 years old. A major resource is needed to further operate the pipelines which span approximately 13,000 kilometers and are 11 to 33 years old. Under these conditions, the fact that Russia acts reluctant and is willing to invest in other directions except for maintenance and repair poses another great risk to the countries that benefit from those pipelines.

Even if the TurkStream project is not carried out, it is understood that the West Line will fail to perform its former function in the future. Therefore, the problem of a lack of infrastructure that would arise in the future has been eliminated with TurkStream.

Impacts on dependency

It is understood that Turkey bought an average of 26.4 billion cubic meters of natural gas per year from Russia between 2011-2018. The lowest amount was 24 billion cubic meters in 2018. It is seen that the EU countries import an average of 40% natural gas from Russia. This rate increases to 100% in some EU countries. Turkey continues to take significant steps to decrease its dependency on Russia. Benefitting more from renewable energy sources in Turkey has led to a decrease of the gas rate coming from Russia from around 60% to around 48% in 2018. Moreover, in case of full usage of the capacity of natural gas coming from TANAP allocated for Turkey in 2020, this rate is expected to fall to around 40%.

Turkey consumes an annual average of 50 billion cubic meters of natural gas and procures 99% of this amount from abroad. Not depending on one resource, it puts forward strategies prioritizing diversifying source countries with new pipelines such as TANAP as well as routes.

Likewise, Turkey, which aims to reach a storage capacity for around 10 billion cubic meters of natural gas in 2023, has the technical capacity to procure half of the natural gas it consumes as LNG (liquefied natural gas). Turkey, which follows the policy of reducing natural gas usage rates in electricity generation, increases its standing as a regional actor by participating in international energy projects. While all these developments decrease Turkey’s dependency on Russia, it increases Russia’s dependency on Turkey compared to the past with the TurkStream project.

It is understood that the natural gas structure in the Balkans will change to a certain extent with the arrival of TurkStream to the region. It is stated that the West Natural Gas Pipeline will become dysfunctional due to TurkStream. As Hungary, Bulgaria and Serbia will meet their increasing natural gas demand with TurkStream, Turkey’s importance will increase in terms of those countries’ energy security. Also, the BOTAS and GAZPROM partnership, which will operate the second line that will reach Europe, means that Turkey will economically benefit from TurkStream.

US sanctions and possible results

It is claimed that TurkStream does not align with the strategic goals of the U.S. and the EU’s Third Energy Package legislation. On the other hand, the U.S. shows that it is against TurkStream with its CAATSA (Countering America’s Adversaries Through Sanctions Act) sanctions. The U.S. Congress increased its pressure on TurkStream and Nord Stream 2 with the National Defense Authorization Act for Fiscal Year 2020 it passed in December 2019 and by supporting some sanctions. The implementation of items targeting ships involved in laying pipes on the seabed in these projects may be on the agenda in 2020. However, as Turkish firms do not carry out the sea part of the project, it is not possible to directly implement U.S. sanctions on Turkey. On the other hand, since the TurkStream project was initiated earlier than CAATSA’s enactment, it should not be involved in these sanctions.

While TurkStream brings Ankara and Moscow closer, it also presents gains for Turkey concerning Syria and Libya, which are important issues of foreign policy. The progress and increase in this cooperation will provide significant flexibility to Turkey in foreign policy.

On the other hand, transmission of natural gas, which the EU demands, through Turkey to the EU and the increase of the amount that is carried by time are seen as a result of this cooperation. The EU will have to import more natural gas if Norway’s reserves, which are seen as an insurance due to its closeness to the EU, expire in a short time. While the U.S.’ external natural gas dependence rate was 47% in 2000, this rate increased to 55% in 2017.

It is foreseen that this rate will increase to around 70% in 2030. For this reason, Turkey stands out as one of the most reliable routes at the point for meeting the EU’s energy needs.

Projects such as TurkStream and TANAP have emerged to meet Europe’s natural gas needs. Increasing the number of these projects contributes positively especially to security and economic issues at regional and global levels. New cooperation with countries close to this geography, such as Turkmenistan, which has the largest proven natural gas reserve in Central Asia, may be established. Turkey, which is one of the key countries that will play an active role in transmitting Turkmen gas to Europe, can display its playmaker role easier with the experience it gained through TANAP and TurkStream. Therefore, it can be said that Turkey’s leadership role in energy is being strengthened in terms of the realization of international projects.

*Opinions expressed in this article are the author’s own and do not necessarily reflect the editorial policy of Anadolu Agency.

Gazprom PJSC and Ukraine reached an agreement that will allow Russian gas to flow to Europe via its neighbour through the end of 2024 and settle all of the related legal disputes.
Ukraine’s gas company, Naftogaz PJSC, will organise the transit of Russian gas through the country, with a booked pipeline capacity of 65bn cubic meters for 2020 shipments, Gazprom chief executive officer Alexey Miller said in a statement yesterday.
In 2021-2024, the booked capacities will reach 40bn cubic meters a year, he said. The companies also agreed to mull the possibility of gas transit through 2034, according to a protocol, signed late Friday evening in Minsk. An extension for the following 10 years may be on the same terms as the five-year deal, according to Ukraine’s Energy Ministry.
“The transit via Ukraine will continue and the strategic nature of the transit was understood by everyone and I believe it would help us open a new chapter in this relationship,” EU Commission Vice President Maros Sefcovic told Bloomberg yesterday.
The bilateral agreement paves the way for the continuation of Russian gas flows to Europe via Ukraine, which has been the key transit route for Gazprom even amid the legal spats and political tensions between the two nations.
It also supports Europe’s energy security as Russia has been the European Union’s dominant and often cheapest energy supplier, providing some 37% of the fuel to the region last year. The current 10-year transit deal between Russia and Ukraine expires January 1. “There are very precise deadlines until when everything should happen,” Sefcovic said. “I have no doubt that everything will go smoothly as of January 1 because there was full understanding of what needs to be done.”
Russia and Ukraine reached the deal as the US administration imposed sanctions on Russia’s future subsea gas-export pipeline, Nord Stream 2. The $11bn pipeline is just weeks away from completion, but it has faced criticism from the US, and it wasn’t immediately clear if the pipeline work can be completed without the input of AllSeas Group SA, which said it would halt operations.
Talks to find a deal between Russia and Ukraine intensified in recent days as the deadline loomed. “To be honest we have done almost the impossible in three months,” Ukraine’s Energy Minister Oleksiy Orzhel told reporters in Kiev yesterday.
Under the deal, Gazprom and Ukraine have agreed not to start any new gas lawsuits against each other and to cancel all their current legal claims that haven’t been subject to court rulings, according to Miller. The Russian gas giant will also pay to Naftogaz $2.9bn awarded by the Stockholm arbitration in 2018.
The sum includes a $2.6bn debt and fines accumulated thereafter, a spokesman for Gazprom said in a separate statement. “It is very important that these $3bn in line with Stockholm arbitration will be paid in cash if we implement all the package of proposals before year-end,” Orzhel said. At the same time Ukraine will withdraw its legal claims against the Russian company.
Last month, Naftogaz filed a lawsuit against Gazprom with a court of arbitration in Stockholm, asking to revise transit fees totalling more than $12bn.
Gazprom and the Ukrainian government are also set to sign an “amicable agreement” on cancelling an antitrust claim that has reached about $7.4bn, including fines. All the legal issues should be resolved by December 29, according to the protocol.