Authors: Simon Bennett and Tristan Stanley
The 2018 US Budget Bill, passed by the House and Senate in mid-February, will shape funding for energy technologies for the next decade. Alongside the extension of renewable tax credits and credits for energy efficiency, nuclear and fuel cells, the bill contains a provision that could provide the first significant stimulus to the global fortunes of carbon capture for several years. It is an example of how relatively small policy incentives can tip the scales towards investment when the infrastructure and industrial conditions are already in place, as the United States is leveraging an existing market and pipeline network for enhanced oil recovery (EOR).
The Budget Bill aims to stimulate investment in carbon capture by expanding incentives to companies that can use captured CO2 and reduce emissions as a result. It raises the existing so-called “45Q” tax credit for storing CO2 permanently underground from USD 22 today to USD 50 in 2026. The figure below shows the level of credit available for different combinations of CO2 sources and uses.
IEA analysis suggests it could trigger the largest surge in carbon capture investment of any policy instrument to date. Based on the above levels of revenue support for commercial carbon capture projects, we estimate that the tax credit could lead to capital investment on the order of USD 1 billion over the next six years, potentially adding 10 to 30 million tonnes or more of additional CO2 capture capacity, potentially increasing oil production by 50 to 100 thousand barrels per day. This would increase total global carbon capture by around two thirds and, by incentivising industry to find the lowest-cost projects, could be cheaper than projects already operating around the world. The annual cost to the US taxpayer by 2026, supporting CAPEX and OPEX, would be under USD 800 million.
Carbon capture refers to the separation of carbon dioxide (CO2) from industrial processes before it can be released to the atmosphere and contribute to climate change. It is a key part of the climate change mitigation toolbox because it can tackle emissions sources for which no other technologies are out of the lab and commercially available. These include industrial processes for production of steel, cement and a range of fuels, from gasoline to bioethanol and hydrogen. By retrofitting carbon capture to existing polluting facilities like coal power stations, they have the option of continuing operation with lower emissions, potentially overcoming political and economic obstacles to system transformation.
Of course, something must be done once the carbon is captured. Very large volumes can be injected deep underground and safely trapped for the long term. CO2 can also be trapped underground while being used in enhanced oil recovery (EOR), for which 65 million tonnes are purchased each year by the oil and gas industry and injected into oil fields to increase their productivity. Today, 80% of this CO2 comes from natural underground CO2 deposits and its use has no beneficial impact on greenhouse gas emissions reduction. Using captured CO2 that would otherwise have been emitted instead of natural CO2 therefore gives an environmental benefit and, extending the life of existing oilfields. Besides EOR, smaller volumes of CO2 can be purchased for economic use in chemical processes but may not offer the same level of emissions reduction as underground storage if the process is energy intensive or the final product is combusted, releasing CO2 again.
For achieving the goals set out in the Paris Agreement on Climate Change, any boost for carbon capture utilisation and storage (CCUS) would be welcome. The IEA recently noted that there has been a slump in new projects, with no new projects in the pipeline for construction. The US has been a clear leader accounting for around half of the total investment in CCUS in the decade to 2017.
The biggest opportunities are likely to be in the capture of CO2 from hydrogen plants at refineries and from natural gas processing facilities. Along with hydrogen production at fertilizer plants and bioethanol mills, these represent the lowest cost sources of CO2 at large scale and, unlike the fertilizer and bioethanol industries; they tend to be located close to existing CO2 pipelines for transporting CO2 to oilfields. In general, the lowest cost opportunities for avoiding emissions via CCUS reflect the concentration of CO2 in the flue gases.
Deployment of new carbon capture facilities in these sectors would reflect experience to date. Three quarters of the CO2 capture capacity built in the last decade and operating today has been on hydrogen production, gas processing and ethanol fermentation, all high purity sources of CO2. This represents almost half of all investment in CCUS made in the last decade, providing a strong indication of the sectors for CCUS that are favoured by the market. Twenty nine million tonnes of CO2 are captured today from large industrial sources, 87% of these are used for EOR, of which 78% are in the US.
The overall impact of the 45Q tax credit on stimulating a more sustainable CCUS industry will depend on a number of uncertain factors. We think the following factors are mostly upside risks:
CO2 demand for EOR
Our estimate of the impact of the tax credit assumes that neither CO2 demand nor supply are strongly limiting factors. The 45Q incentive should reduce the price of CO2 from carbon capture facilities to a level in line with that from natural CO2 deposits and unlock demand that is currently limited by the constraints on natural CO2. Taking these constraints into account, the shift of the supply curve resulting from this price reduction should ensure that any future EOR growth is based on captured CO2, not further production of natural CO2 that is already trapped harmlessly underground. From the supply side, it seems feasible that the construction of carbon capture projects could ramp up quickly enough by 2024 to meet much of this demand as long as CO2 offtake contracts and pipeline extensions can be put in place to trigger investment. Ultimately, however, this will depend on the evolution of the oil price – which is currently below the level needed for some, but not all, EOR projects – and the allocation of capital between light tight oil plays and EOR at mature fields.
CO2 demand for non-EOR uses
While the new legislation opens up the tax credit to industrial uses of CO2 – and, by changing the terminology, to industrial uses of carbon monoxide (CO) – the extent of uptake from these businesses is uncertain, and will likely be limited. In addition to being in construction by 2024, three conditions need to be satisfied to claim the credit: the carbon oxide would have otherwise been released to the air; over 25 000 tonnes per year from each carbon capture facility must be converted to products; a life cycle assessment by the regulator must show a benefit to the climate and the tax credit reduced accordingly if the benefit is lower than for long-term CO2 storage.
For carbon monoxide, which already has economic value as a fuel and chemical, we think the tax credit will not be high enough to divert much to new uses. For example, $35 per tonne of CO is around $12 per MWh, so it would not outbid the fuel value of CO. Using CO2 to convert hydrogen to hydrocarbon fuels could potentially exceed the annual volume condition by 2026, to help overcome the difficulties with storing electricity as hydrogen, but this will have a harder time with the life cycle assessment condition. Because the carbon is released when the fuel is burned, we foresee less than half of the tax credit (no more than $17) being available for such uses, which would probably need to be combined with other incentives to kick start an industry (a price of €300 per tonne was suggested by German industry).
The speed with which dedicated CO2 storage sites can be developed
Given that it can take 5-10 years to develop a storage site, with considerable capital put at risk upfront, we expect most CO2 captured to be used for EOR in the near term. Dedicated storage sites, particularly in regions without CO2 pipelines or EOR production, may start to come on line as the tax credit approaches $50. One of the biggest opportunities for using the 45Q tax credit is to capture CO2 from bioethanol plants, which are not only numerous in the United States but emit CO2 of biogenic origin –as a result, storing this CO2 effectively pumps CO2 out of the atmosphere. Many of these plants are not near CO2 pipelines for EOR but the CO2 could be stored permanently underground and qualify for the higher level of tax credit, as at Decatur in Illinois. $22-52 is certainly enough to cover the levelised costs of CO2 storage over the long term, but the geology is not ideal in every location.
Longer term developments
The level of credit rises over time, and then is inflation linked after 2026. As such, 45Q will have limited uptake in the next few years and investment will target carbon capture projects coming online in the mid-2020s, when the higher level of tax credits will be available. Any electricity sector projects – such as coal or gas power plants – would not be expected until the second half of next decade and, even at USD 50, would be limited in number without additional policy measures. Policy measures that could combine with 45Q to significantly multiply its uptake include low carbon fuel standards, in discussion in California, and modifications to the treatment of private activity bonds and master limited partnerships in this area. For direct capture of CO2 from the air, which has estimated costs well in excess of $200 per tonne, a higher level of additional policy support would likely be needed. Technologists with plans to remove carbon from the atmosphere will likely see 45Q as a “nice-to have”, rather than a cue to establish a market for guilt-free CO2. In a supportive move on the other side of the Atlantic, EU legislators agreed in January 2018 to let fuels produced from hydrogen combined with CO2 count towards renewable policy goals only if the CO2 is captured from ambient air.
*Tristan Stanley, IEA Energy Technology Analyst
The U.S. Oil Ambitions Threaten Economy and Sovereignty of Syria
From the very beginning an open U.S. intervention in the Syrian conflict caused heated discussions in the world community concerning legality of activities of the White House in Syria. Many political experts and officials repeatedly spread the opinion that the U.S. military presence in Syria has no legal basis, despite the participation of the U.S.-led International coalition in the fight against ISIS.
The particular interest in legality of the U.S. presence in Syria is caused by its undisguised concern for extraction of Syrian oil, which fields had come under control of pro-American Kurdish groups after military operations. Moreover, economic reasons for U.S. forces participation in the Syrian conflict have been personally announced by Donald Trump during one of his press conferences. And all this was after a long time since the official announcement of a clear victory over ISIS in Syria.
According to official statistics reflecting the Syrian economy, it is possible to see how harmful a long-term war with the terrorist organizations and intervention of foreign countries was for Damascus. For example, the oil industry had been playing a very important role in budgeting Syria and average oil production had been 385 thousand barrels per day. At this moment, as a result of the conflict and the economic crisis in conjunction with assignment of the largest oil fields by the U.S. forces in the Eastern Syria the oil production index fell 24 times, and the total damage to the Syrian economy amounted to 400 billion U.S. dollars. According to the Syrian government advisory council, the oil industry of the country will be able to reach the level of 2011 not earlier than in 5 years at best.
It should be especially noted the recent agreement of the American oil company “Delta Crescent Energy” with Kurdish-led Autonomous Administration of Northeast Syria to develop and modernize existing oil fields. At the same time it is really hard to know something about this company; it has no markets, own oil refineries and even a website. And the fact that it was founded by the former American official only strengthens an ordinary opinion about close ties between “Delta Crescent Energy” and the U.S. Ministry of Defense.
Not only does this agreement indirectly confirms the White House’s concern for preserving the military contingent in Syria, it also poses a serious threat to the sovereignty of the Arab state and its integrity. Having relied on the Kurdish administration, Washington will create preconditions for an independence of Kurds from the rest of Syria that will increase existing tensions between the largest ethnic groups of Syria. Thus, the U.S. by supporting Kurds got an allied regional formation that protects the oilfields.
The U.S. policy in the Middle East is successful if we estimate it from the side of oil companies’ administrations close to the White House. However, from the point of view of those countries, where Washington interfered in the pursuit of crude oil, suffer huge economic losses along with damage to their state integrity. The Syrian economy is seriously harmed by the ongoing conflict and Western sanctions. And such aggressive policy of the United States is only worsening a humanitarian disaster in Syria.
The Rise of Targeted Sanctions Towards International Energy Companies & Collateral Effects
International sanctions are becoming a major foreign policy tool against state-owned oil & gas companies in jurisdictions like Russia and Venezuela that were not used to this type of measure against its economic interest. Until a few years ago, companies like Rosneft Oil Company and Petróleos de Venezuela, S.A. (PDVSA), easily accessed the international financial markets with multibillion global bond emissions and international financings that were extremely attractive to major investment banks.
The first type of applicable sanctions laws are “primary” sanctions, which are traditional U.S. sanctions, and apply only to prohibited transactions with a U.S. nexus. The second type of applicable sanctions laws are “secondary” sanctions, which apply to transactions that are entirely outside of the jurisdiction of the U.S. but seek to sanction specific types of conduct that the U.S. deems particularly contrary to U.S. policy.
In other words, while the U.S. Department of the Treasury’s Office of Foreign Assets Control (OFAC) generally limits its jurisdiction to U.S. persons, in some instances the national security imperative is so great the OFAC will decide to use secondary sanctions even when there is no U.S. person involved at all, such as targeted sanctions against oil tankers delivering PDVSA’s crude oil.
The sophistication of the sanctions regime is reaching new levels, specifically within the Oil & Gas sector. Notably, OFAC is targeting all types of actions that are currently seeking to circumvent its sanctions regime, with broader consequences to the targeted companies and persons.
The Rosneft & PDVSA Case
Rosneft, PDVSA, and international companies delivering crude oil have been targeted by OFAC. More than 25 oil tankers and 17 shipping companies that were selling crude oil for PDVSA have been sanctioned. This new trend of OFAC sanctions began in April 2019, when 4 shipping companies and 10 ships related to oil trading with PDVSA were targeted.
In February 2020, Rosneft Trading, S.A., and its President Didier Casimiro were subject to OFAC sanctions for the trading of Venezuelan oil. The U.S. Department of the Treasury determined that 80% of the oil tankers used by PDVSA to export oil were from Rosneft. As a result of the sanctions, some crude oil deliveries by Rosneft to China were rejected by potential buyers.
Afterward, in March 2020, TNK Trading international S.A. (TTI), a subsidiary of Rosneft, was targeted by OFAC for replacing Rosneft Trading, S.A. trading operations with PDVSA in order to evade OFAC sanctions. In January 2020, 14 million barrels of crude oil were purchased by TTI from PDVSA. Rosneft stated that the trades were repayments arising out of a $6.5 billion loan to PDVSA with $800 still outstanding by the third quarter of 2019.
PDVSA’s Access to International Financial Markets
After billions of dollars borrowed from major investment banks and global bond emissions, PDVSA’s access to international financial markets was severely affected by its OFAC designation in January 2019.
Effectively, this meant that PDVSA assets under U.S jurisdiction were blocked, OFAC also prohibited all of PDVSA’s related transactions within U.S. jurisdiction, unless otherwise licensed, authorized, or under the scope of the SDN designation. U.S. companies like Chevron, Schlumberger, Baker Hughes, and Weatherford operating in Venezuela requested general licenses to OFAC in order to keep its operations on going with PDVSA.
Bypassing the Sanctions Regime
Iran, Mexico, individuals, and companies have been trying to bypass the OFAC sanctions regime. In May 2020, the U.S. Department of State, OFAC, and the U.S. Coast Guard issued an advisory to international shipping companies to be aware of tactics to evade sanctions like ship-to-ship transfers and by not using the mandatory tracking devices. Such techniques were implemented in crude oil, refined petroleum, and petrochemicals deliveries between Iran and Venezuela.
In Mexico based individuals and entities that were part of a PDVSA sanctions scheme to bypass sanctions were targeted in June 2020. OFAC SDN Alex Nain Moran (Saab) and associates, were evading U.S. Sanctions by doing “oil for food” schemes to sell Venezuelan crude oil. The Mexico based companies, brokered the re-sale of over 30 million barrels of PDVSA’s crude oil by largely replicating Rosneft Trading’s operations and Asian buyers, which did not result in food deliveries to Venezuela according to OFAC.
Saab, last year was charged with money laundering in connection with a bribery scheme by the U.S. Department of Justice (DOJ). The DOJ stated in the indictment that Saab violated the Foreign Corrupt Practices Act (FCPA) by paying bribes to Venezuelan government officials in order to access the controlled exchange rate by the Venezuelan government, with import documents for goods and materials that were false and fraudulent and that were never imported into Venezuela.
Moreover, the DOJ alleges that $350 million of bribe payments were transferred through bank accounts located in the Southern District of Florida and then to overseas accounts owned or controlled by Saab. To date, Saab is undergoing an extradition process in Cape Verde to the U.S. in relation to this indictment.
Collateral Effects of the Sanctions Regime
Different collateral effects of the sanctions regime have affected the operations of global oil & gas companies. PDVSA lost three oil supertankers to PetroChina Co Ltd, OFAC sanctions left the ships without insurance, since the insurance companies did not want to be subject to sanctions, this led to the bankruptcy of the joint venture between PDVSA and PetroChina.
The joint venture was created in order to export PDVSA’s oil to China, and other markets. Protection & Indemnity (P&I) insurance for vessels is mandatory pursuant to Singapore law, without the P&I the oil tankers are not able to navigate.
On the other hand, Rosneft announced the sale of its Venezuelan assets to a company 100% owned by the Russian Government, it also terminated all its operations in Venezuela. The selling of the assets is a way to protect Rosneft from current and future sanctions targeted against PDVSA.
The latest escalation to enforce OFAC sanctions is the U.S. seizure of four Iranian fuel tankers heading for Venezuela. A civil forfeiture complaint alleged that a businessman of the Iranian Revolutionary Guard Corps, designated by the U.S. as a foreign terrorist organization, arranged the fuel sale.
U.S. officials threatened the ship owners, insurers, and the captain of the four Iranian fuel tankers with targeted sanctions to force them to hand over the cargo. As a result, a total of 1.116 million barrels of petroleum are now in U.S. custody, and the websites of the Iranian companies accused of shipping fuel to Venezuela were seized by the DOJ.
The Trump administration has been stepping up the pressure with targeted sanctions and other measures on Venezuela to comply with sanctions against international oil companies like PDVSA, Rosneft, ship owners, and any other entity or person dealing with PDVSA’s crude oil.
Across the Atlantic, E.U. sanctions have proven to be far less aggressive and targeted, with less notable enforcement proceedings against E.U sanctions violations, and with no direct sanctions against PDVSA or towards oil tankers delivering Venezuelan oil.
The collateral effect of targeted U.S. sanctions designation encompasses far-reaching implications since foreign companies must withdraw their business with the sanctioned target or they could also be barred from accessing the U.S. financial system and economy. Material assistance and any transaction with a company sanctioned by the U.S. could be seen by OFAC has assistance in order to bypass the sanctions regime which is the case of the targeted sanctions against Rosneft.
Lifting of OFAC sanctions is possible, targeted oil tankers subject to PDVSA’s sanctions have been delisted when the companies have agreed to expand its risk-based sanctions compliance programs based on the OFAC public guidance model. Moreover, the companies have also pledged to terminate participation in the oil sector of the Venezuelan economy so long as the Maduro government remains in power.
Thus, due to the complexity and ramifications of the U.S. sanctions regime against energy companies like PDVSA and Rosneft, global financial institutions, energy companies, and service providers should implement strong compliance programs to prevent targeted sanctions by OFAC.
Azerbaijan Becomes Turkey’s Top Gas Supplier
Azerbaijan has become Turkey’s major gas supplier and this could have major geopolitical ramifications for the region. But it also fits into Turkey’s efforts of the past several years to diminish its dependence on Russian gas. Hence Ankara’s particularly harsh position regarding the recent Armenia-Azerbaijan fighting in the Tovuz region where regional gas, oil and railway infrastructure runs.
From January-May of this year, Turkey imported 4 527,39 cubic meters of Azerbaijani gas (from Shah Deniz field). This is some 20,4 percent more in comparison to the same period of 2019. On the other hand, in May 2020 the import from Russia diminished by almost 62% compared to the same month in 2019. In May 2020, Azerbaijan officially became Turkey’s top gas supplier.
Overall this is a continuation of the trend from 2019 when Azerbaijan’s share in Turkey’s gas supplies reached 21.2 percent, which is some 6.23 percent more compared to the same period of 2018.
This became possible after the launch of TANAP in late 2019. The $6,5 bln. project is essentially a part of the $40 billion Southern Gas Corridor with a number of pipelines connecting Azerbaijan’s Shah Deniz II field to the vast European market. TANAP has the capacity to transport up to 16 billion cubic meters (bcm) of Caspian gas per year: 10 bcm go to Europe and 6 bcm to the Turkish market. Potentially, the TANAP could have a capacity of up to 31 bcm.
Previously it was reported that the capacity of TANAP would reach a cap of 6 bcm of natural gas by the end of June. To reach this milestone the volume went up gradually, first reaching 11,3 million cubic meters (m3) (July 2019). Moreover, this July the highest volume of 17 million m3 was recorded.
This happens at the time when Russian gas flows to Turkey are at a low point. Repair works were announced, which further contributes to the decrease of the Russian gas potential in Turkey. As a result, the $7.8 billion, 930 km TurkStream pipeline, built across the Black Sea and inaugurated in early 2020, is superseded by Azerbaijan, as a major gas supplier. The trend is self-revealing. In 2017, Gazprom exported 52 percent of Turkey’s total gas imports, in 2018 the figure stood at 47 percent and in 2019 at just 33 percent (15.9 bcm).
For example, in March, Turkey received nearly 924 million m3 of Azeri gas, which maked up 23,45 percent of the total volume of gas supplies to Turkey. Azerbaijan also pushed Iran, which together with Russia, are now Turkey’s second and third largest gas providers.
The decrease of Russian gas flows is also caused by the Turkish national company BOTAŞ increasing imports from Algeria and Nigeria. For Gazprom it also becomes increasingly difficult to compete with large LNG supplies that Turkey imports from the US. A look at the dynamics of LNG imports reveals an interesting trend – over the past 10 years the share of LNG steadily increases in Turkey. In 2013-2019 period, the share of LNG in Turkish gas imports rose from 6.1 bcm to 12.7 bcm.
Geopolitics of gas supplies
The decline of Russian gas supplies means Turkey would have space for geopolitical manoeuvres in an increasingly unstable period of time when Russian influence grows along Turkey’s borders. Moreover, Ankara might gain even greater leverage as various contracts guaranteeing gas flows from Russia expire in coming years and extensive talks will likely be held.
Indeed, geopolitics might be at play behind Turkey’s moves and aspirations to diminish dependence on Russia as BOTAS, the company which oversees the country’s gas import, is a state-run enterprise. This means that what happens in Syria or elsewhere easily influences the calculus of Turkey’s gas industry.
And there are reasons to worry for Turkey as Russia’s military influence in Syria and the Black Sea grows, and differences over the Libyan conflict abound. It is thus natural for Turkey to look at different ways to reduce its dependence on Russian gas. This creates a perfect opportunity for Azerbaijan to enhance its position as the region’s major gas supplier and thus further solidify its relations with Turkey. Turkey, on the other hand, is interested in an unhindered flow of Azerbaijani gas and, as other regional or global powers, is willing to defend its gas supply chain politically and, if necessary, even use a limited military force.
Perhaps this could explain Turkey’s statements regarding the recent uptick of fighting between Armenia and Azerbaijan. The violence took place along the Tovuz district of Azerbaijan. Surprisingly, the region is far distanced from Nagorno Karabakh, which is usually a centre for either large-scale fighting (as in 2016) or daily small-scale disturbances along the contact line. What relates the fighting in Tovuz to the geopolitics of gas supplies is the fact that the region is a vital land corridor for regional transport and energy export routes. This includes the Baku–Tbilisi–Ceyhan (BTC) pipeline, the South Caucasus natural gas pipeline (SCP) and the Baku–Tbilisi–Kars (BTK) railway. This is the infrastructure which connects Azerbaijan to the West and represents a larger trans-Eurasian East-West corridor that has been championed by the West since the end of the Soviet Union. But more importantly, as argued above, the corridor allows Ankara to seek a partial alternative to the dependence on Russian gas. Therefore, any military moves near those strategic routes could invite Turkish action.
This could also explain why Ankara was especially vocal in its support for Baku during and after the Tovuz fighting. For example, Turkey’s defence industry chief stated the country was ready to help its eastern ally. Moreover, Turkey and Azerbaijan held military drills right after the end of the fighting. The exercises involved the land and air forces in multiple locations such as Baku, Nakhchivan, Ganja, Kurdamir and Yevlakh. The signal was clear: increased Turkish military cooperation with Azerbaijan might follow if threat to the infrastructure is not neutralized.
In the end, the clashes did not damage Azerbaijan’s energy and transport infrastructure, but both Baku and Ankara saw how vulnerable they could be. Both easily recall the Georgia-Russia war of 2008 when SCP, BTC and the Baku–Supsa oil pipeline were effectively shut down because of the ongoing military operations and general uncertainty in the South Caucasus.
As Turkey aims to transform itself into the region’s energy hub rather than serving only as a transit country, its relations with Azerbaijan will likely further solidify. Azerbaijani gas will continue to play a vital role in this emerging Turkish strategy. Moreover, both will seek deeper military cooperation to defend its critical infrastructure. Perhaps, this could serve as a necessary impulse for the Trilateral format of Turkey-Georgia-Azerbaijan to expand their cooperation. Much will also depend on Russian gas supplies, but as the gas supply trend of recent years and regional geopolitical developments indicate, Turkey will continue decreasing its dependence on Russian import.
Author’s note: first published in Caucasuswatch
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