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Overview

Oman is the largest oil and natural gas producer in the Middle East that is not a member of the Organization of the Petroleum Exporting Countries.

Located on the Arabian Peninsula, Oman’s proximity to the Arabian Sea, Gulf of Oman, and Persian Gulf grant it access to some of the most important energy corridors in the world, enhancing Oman’s position in the global energy supply chain (Figure 1). Oman plans to capitalize on this strategic location by constructing a world-class oil refining and storage complex near Ad Duqm, Oman, which lies outside the Strait of Hormuz (an important oil transit chokepoint).

Like many countries in the Middle East, Oman is highly dependent on its hydrocarbons sector. The Oman Ministry of Finance stated that finances have been severely affected by the decline in oil prices since mid-2014. In 2016, Oman lost more than 67% of its oil and natural gas revenues compared with oil revenue the country earned in 2014, despite achieving record production.1 Oil revenue accounted for 27% of Oman’s gross domestic product (GDP) in 2016, a decrease from 34% of GDP in 2015 and 46% in 2014, according to the Central Bank of Oman.2

The ninth iteration of the Oman 5-Year Plan (2016-2020) released in 2016, created in the context of sustained low oil prices, aims to enhance the country’s economic diversification by adopting a set of sectoral objectives, policies, and mechanisms that will increase non-oil revenue. Oman’s diversification program is largely aimed at expanding industries such as fertilizer, petrochemicals, aluminum, power generation, and water desalination. Concerted efforts to develop these sectors would also accelerate non-oil job growth in coming years.3However, with rising production levels and a growing petrochemical sector–which relies on liquefied petroleum gases (LPG) and natural gas liquids (NGL)–the country is unlikely to significantly alter its dependence on hydrocarbons as a major revenue stream in the short term.

Figure 1. Map of Oman

Map of Oman

Source: Central Intelligence Agency World Factbook

Petroleum and other liquid fuels

Oman’s petroleum and other liquids production averaged more than 1 million barrels per day in 2016, its highest production level ever. Oman was on track to maintain this production level in 2017, but it reduced production to approximately 970,000 barrels per day in early 2017 to meet the production cut it agreed to, along with members of the Organization of the Petroleum Exporting Countries (OPEC).

Sector organization

The Ministry of Oil and Gas coordinates the government’s role in Oman’s hydrocarbon sectors. Final approval on policy and investment, however, rests with the Sultan of Oman. The majority state-owned Petroleum Development Oman (PDO) holds most of Oman’s oil reserves and operates the Sultanate’s largest block, Block 6. PDO is responsible for more than 70% of the country’s crude oil production.4 In addition to the government’s 60% ownership stake in PDO, Shell (34%), Total (4%), and Portugal’s Partex (2%) also own stakes.5 In addition to the PDO, the Oman Oil Company (OOC) is responsible for energy investments both inside and outside of Oman. The OOC is fully owned by the government. The Oman Oil Refineries and Petroleum Industries Company (ORPIC) is owned by the Government of the Sultanate of Oman and by the OOC. It controls the country’s refining sector and owns both of Oman’s operating refineries, Sohar and Mina al-Fahal.6

The U.S. firm, Occidental Petroleum (Oxy), is the second-largest operator after PDO and has the largest presence of any foreign firm in Oman. Oxy operates mainly in northern Oman at Block 62 and Block 9, along with the Mukhaizna field in the south. Lebanese independent, Consolidated Contractors Energy Development (CCED), operates Blocks 3 and 4 with a 50% stake alongside Sweden’s Tethys Oil (30%) and Japan’s Mitsui (20%). Daleel Petroleum is a 50:50 joint venture between Omani private firm Petrogas and Chinese state firm China National Petroleum Corporation (CNPC) and operates Block 5.

Upstream

According to the Oil & Gas Journal, Oman had 5.4 billion barrels of estimated proved oil reserves as of January 2017, ranking Oman as the 7th largest proved oil reserve holder in the Middle East and the 22nd largest in the world.7 The majority of the fields are located within PDO’s concession area.

Figure 2. Oman major oil and natural gas infrastructure

Map of Oman major oil and natural gas infrastructure

Source: U.S. Energy Information Administration, IHS EDIN

Exploration and production

Enhanced oil recovery techniques helped Oman’s oil production rebound from a multi–year decline in the early 2000s.

Oman’s petroleum and other liquids (total oil) production ranks 7th in the Middle East and ranks among the top 25 oil producers in the world. Oman is the largest oil producer in the Middle East that is not a member of the Organization of the Petroleum Exporting Countries (OPEC). Oman’s annual petroleum and other liquids production peaked at 972,000 barrels per day (b/d) in 2000, but dropped to 715,000 b/d by 2007. Oman successfully reversed that decline, and total oil production has risen, hitting a new peak of a little more than 1 million b/d in 2016 (Figure 3). Enhanced Oil Recovery (EOR) techniques helped drive this production turnaround, along with additional production gains as a result of previous discoveries.

Several recent developments could contribute to future oil production growth in Oman. The major oil discoveries of 2016 were in north Oman (Figure 2, Table 1).

Enhanced oil recovery

Oman’s ability to increase its oil and natural gas production relies heavily on innovative extraction technologies, such as EOR. Several EOR techniques are already used in Oman, including polymer, miscible, and steam injection techniques.8 Because of the relatively high cost of production in the country, Oman’s government offers incentives to international oil companies (IOCs) for exploration and development activities related to the country’s difficult-to-recover hydrocarbons. The government enlists foreign companies in new exploration and production projects, offering generous terms for developing fields that require the sophisticated technology and expertise of the private sector. Given the technical difficulties involved in oil production, the contract terms for IOCs have become more favorable in Oman than in other countries in the region, with some allowing significant equity stakes in certain projects.

Block 6, located in central and southern Oman and operated by PDO, is the center of current EOR operations, using all four of the EOR techniques with the Marmul field (polymer), Harweel field (miscible), Qarn Alam field (steam), and Amal-West field (solar). Solar EOR at Alam-West in southern Oman was the first solar EOR project in the Middle East, completed by GlassPoint Solar in 2012 and commissioned in early 2013. This project uses the production of emissions-free steam that feeds directly into current thermal EOR operations, reducing the need to use natural gas in EOR projects.9

In partnership with PDO, GlassPoint Solar is currently building the Miraah solar thermal plant to improve recovery of heavy and viscous crude oil from Amal oil field. The plant is expected to produce 1,021 megawatts (MW) of peak thermal energy in the form of 6,000 tons of solar steam each day (no electricity is produced). Construction on the project began in October 2015, with steam generation from the first glasshouse module expected in 2017.10

However, in 2016, because of relatively low crude oil prices and the resource-intensive nature of EOR, PDO announced it was placing more emphasis on accelerating conventional oil and gas opportunities instead of short-term expansion of EOR projects.11

Oman petroleum and other liquids production and consumption

Table 1: New oil discoveries, 2016ProjectFieldCompanyContingent Reserves, million barrels*ShammarLekhwairPDO40Qarn Alam-RabaQarn AlamPDO27Total  67The Society of Petroleum Engineers separates the term contingent from the term reserves. “Contingent resources are less certain than reserves. These resources are potentially recoverable but not yet considered mature enough for commercial development due to technological or business hurdles.” 
Source: Oman Ministry of Oil and GasConsumption and refining

Oman consumed 186,000 b/d of petroleum and other liquids in 2016 (Figure 4), most of which were petroleum products refined at Oman’s refineries and a small amount that was imported.

Oman is not a major refined petroleum product producer, although it has plans to expand the country’s refining and storage sectors. Oman aims to capitalize on its strategic location on the Arabian Peninsula by expanding its refining capabilities.

Oman has two refineries, Mina al Fahal and Sohar. As of early 2017, Minal al Fahal was operating at 106,000 b/d and Sohar at 116,000 b/d.12 Plans are underway to upgrade the facility at Sohar as part of the ORPIC-led Sohar Refinery Improvement Project (SRIP), scheduled for completion in 2017.13 Sohar’s capacity is expected to expand to 197,000 b/d from 116,000 b/d. In February 2017, ORPIC announced the mechanical completion of all Sohar units as part of the expansion project. A major bunkering and storage terminal near Sohar is scheduled to be completed in 2017, and the facility’s location outside the Strait of Hormuz could make it an attractive option for international crude oil shippers.14

The OOC and Kuwait Petroleum International (KPI) have signed a partnership agreement for their Ad Duqm Refinery and Petrochemical Industries Company (DRPIC) joint venture to build a 230,000 b/d export refinery in a special economic zone under development at Ad Duqm on the Arabian Sea coast of central Oman and a 200 million barrel crude oil storage terminal at Ras Markaz.15 The storage terminal, with phase one estimated to be complete in 2019, will be one of the world’s largest crude oil storage facilities.16 The Ad Duqm refinery could be operational by 2022, with most of the plant’s output to be exported.17 According to the OOC, the cost of developing the refinery will be $6 billion–$7 billion. Both Oman and Kuwait will provide crude feedstock.

Oman does not have any international oil pipelines, although plans are in place to expand the country’s domestic pipeline infrastructure. The Muscat Sohar Pipeline Project (MSPP), built by ORPIC and scheduled to be completed in 2017, is a 180-mile refined product pipeline that will connect the Mina al-Fahal and Sohar refineries with a new storage terminal near Muscat airport and reduce tanker traffic between the two coastal facilities.18 

Oman petroleum petroleum and other liquids consumption, 2016

Exports

Oman is an important oil exporter, particularly to Asian markets. In 2016, virtually all of the country’s crude oil exports went to countries in Asia, with 78% going to China.

Oman’s only export crude oil stream is the Oman blend, with an API gravity of 32, medium-light and sour (high sulfur- 1.33%) crude. Oman is an important crude oil exporter, particularly to Asian markets (Figure 5). In 2016, Oman exported 912,500 b/d of crude oil and condensate, its highest level since 1999.19

China is Oman’s largest export market, and that country received 78% of Oman’s crude oil exports in 2016, while Taiwan received the second-highest volume, despite falling by almost one-third from 2015 levels. Thailand, which had previously been a consistent purchaser of 40,000 to 50,000 b/d of Omani exports, bought only two small cargoes in 2016.20

Oman crude oil exports by destination, 2016

Natural gas

The greatest growth potential for Oman’s natural gas production is in the Khazzan-Makarem field, Block 61. The planned start–up of that field in late 2017 could significantly ease pressure on Oman’s natural gas supplies.

Sector organization

PDO has an even greater presence in the natural gas sector than it does in the oil sector, accounting for nearly all of Oman’s natural gas supply, along with smaller contributions from Occidental Petroleum, Oman’s largest independent oil producer, and Thailand’s PTTEP. The Oman Gas Company (OGC) directs the country’s natural gas transmission and distribution systems. The OGC is a joint venture between the Omani Ministry of Oil and Gas (80%) and OOC (20%). Oman Liquefied Natural Gas (Oman LNG)–owned by a consortium including the government, Shell, and Total–operates all liquefied natural gas (LNG) activities in Oman through its three liquefaction trains in Qalhat near Sur.21

Exploration and production

Oman’s potential for natural gas production growth may be substantial, supported by promising developments in several new projects.

According to the Oil & Gas Journal, Oman held 23 trillion cubic feet (Tcf) of proved natural gas reserves in 2016.22 Oman’s natural gas production grew to 1.16 Tcf in 2016, turning around a recent decline and surpassing the previous high of 1.15 Tcf in 2013. Approximately 80% of production was from non-associated fields.23

Consumption more than doubled from 2006 to 2016, increasing from 380 billion cubic feet (Bcf) in 2006 to 820 Bcf in 2016 (Figure 6). Oman consumes slightly more than 70% of the natural gas it produces. Natural gas is becoming a key source of energy to the Omani economy with its increased focus on economic diversification away from oil.24 The Central Bank of Oman estimates that demand for natural gas will continue to rise going forward with the number of energy-intensive industries coming online combined with rising demand in the electric power sector.25 The concern over rising natural gas consumption prompted the Oman LNG company to announce in 2015 that it would divert all its exported volumes of natural gas away from foreign markets and toward domestic consumers by 2024.26

The greatest growth potential for Oman’s natural gas production is in the Khazzan-Makarem field in BP’s Block 61. The field is a tight gas formation, and BP proposed two phases to develop the 10.5 Tcf of recoverable gas resources. Combined plateau production from Phases 1 and 2 is expected to total approximately 1.5 billion cubic feet per day (Bcf/d), equivalent to about 40% of Oman’s current total domestic gas production.27 This project will involve construction of a three-train central processing facility with associated gathering and export systems and drilling about 325 wells over a 15-year period.28 BP estimates that Phase 1 of the project is more than 80% complete29 and will be online by the end of 2017.30 The start-up of the Khazzan tight gas field will significantly ease the pressure on Oman’s natural gas supplies.

The Rabab Harweel integrated project (RHIP), located in Block 6, is PDO’s largest capital project underway. The project integrates sour miscible gas injection (MGI) in multiple oil reservoirs with production and pressure maintenance of a government gas condensate field, and it will also contribute to easing Oman’s overall natural gas demand. The RHIP is slated for completion in 2019.31

Oman natural gas flows and net exports, 2000-2014

Exports

Oman is a member of the Gas Exporting Countries Forum (GECF) and exports natural gas as LNG through its Oman LNG facilities near Sur, in the Gulf of Oman. In 2016, Oman exported 358 Bcf of natural gas (Figure 7).32 Nearly all of Oman’s natural gas exports go to South Korea and Japan, accounting for 80% of exports in 2016.33

Oman’s natural gas sector grew in importance over the past two decades, largely the result of two LNG trains that opened in 2000 at the LNG complex at Qalhat, near Sur, operated by Oman LNG (a joint venture between PDO and other shareholders). The third LNG train, operated by Qalhat LNG SAOC and built alongside the two existing trains, entered into production in 2005. Qalhat merged into Oman LNG in 2013. Its main shareholders are the Omani state (51%) and Shell Gas B.V (30%).

South Korea is Oman LNG’s primary buyer. Oman’s LNG exports have increasingly been under pressure as rising domestic consumption has cut into volumes available for export. LNG supplies received a boost last year with lower consumption from power stations, and these supplies will see a further boost from new production when the Khazzan gas field comes online in 2017. Khazzan volumes are primarily designated for domestic consumption, with excess volumes exported from Oman’s LNG facilities.

The Sultanate has been focused on diversifying its LNG export destinations because regional demand for LNG is growing. Oman LNG’s 2016 Annual Report reported the first-ever sales of two spot cargoes to Kuwait and Jordan as representing “new departures for our company” by exporting to new geographic destinations.34

Oman LNG exports

Imports

Oman has one international natural gas pipeline–the Dolphin Pipeline–that runs from Qatar to Oman through the United Arab Emirates (UAE). Oman is not a major importer of natural gas, although the country imported approximately 74 Bcf of natural gas in 2016 from Qatar through the Dolphin Pipeline.35 According to the Omani government, the imports through the Dolphin Pipeline are necessary to meet the rising level of domestic natural gas consumption (including re–injection in oil wells).

In March 2014, Oman signed a memorandum of understanding with Iran on a natural gas import contract. The deal will deliver approximately 353 million cubic feet of natural gas per year through a new pipeline under the Gulf of Oman, much of which is slated to be re-exported as LNG. A new route was agreed upon in February 2017 to avoid UAE waters, and Iran is expecting natural gas to begin flowing in 2020.36

Electricity

Oman’s electricity sector relies heavily on domestic natural gas to fuel electricity generation.

The Authority for Electricity Regulation Oman (AER Oman) regulates the country’s electricity and associated water sectors. Its primary functions include implementing general policy from the state, licensing, compliance, and coordination between the various ministries, organizations, and stakeholders in the sector. The Oman Power and Water Procurement Company (OPWP) is the planning body for power supplies in Oman, and the Oman Electricity Transmission Company (OETC) is in charge of the country’s transmission networks.

Oman’s electricity sector has two major networks–the Main Interconnected System (MIS) and the Salalah system. The MIS, the larger of the two, covers most of the northern area of Oman. The Dhofar Power System (DPS) covers the city of Salalah and surrounding areas in the Governorate of Dhofar in the south. Areas outside both networks get electricity from the Rural Areas Electricity Company (RAECO), primarily from diesel generators.37 The Sultanate’s power plants are almost entirely natural gas-fired, and OPWP expects peak demand from power plants connected to each of Oman’s two main power grids to rise by 6% per year through 2023.38

Oman’s electric generation more than doubled between 2006 and 2016, from 13 billion kilowatthours (kWh) to 33 billion kWh. Electricity consumption over the same period also grew at a fast rate, tripling from 10 billion kWh to 30 billion kWh.39 Oman generates electricity primarily from natural gas, although it also has some generation from diesel/distillate.

Oman is a part of the Gulf Cooperation Council’s (GCC) grid interconnection system, which allows for electricity transfers between the six connected countries (Kuwait, Saudi Arabia, Qatar, Bahrain, the United Arab Emirates, and Oman).

OPWP plans to raise electricity generating capacity by 51% from 7.77 gigawatts (GW) at the end of 2016 to 11.7GW in 2023 to meet rising demand. OPWP’s 2017 Seven-Year Plan sees peak power demand rising by 53%, from 6.52 GW in 2016 to 9.96 GW in 2023.40 Eleven firms have submitted applications to develop a 750–850 MW capacity power plant at Misfah for start-up in 2022. Misfah will be the first conventional large-scale power plant for which Oman’s Ministry of Oil and Gas will not guarantee a supply of natural gas fuel.41

Oman has a growing renewable energy sector, with several projects making progress. RAECO plans to install 90 MW of renewable capacity by 2020. UAE’s Masdar was awarded a contract to build the 50 MW wind farm at Harweel in the Dhofar region, estimated to start-up in 2017.42 In July 2015, Oman’s first commercial solar power project, with a 307 kilowatt-capacity, started generating electricity. RAECO will purchase electricity for 20 years from this plant operated by Bahwan Astonfield Solar Energy Company.43 Although Oman does not currently have a nuclear energy program, the country joined the International Atomic Energy Agency in 2009. Currently, the country has no plans to construct any nuclear generating facilities.

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Average U.S. construction costs for solar and wind generation continue to fall

According to 2018 data from the U.S. Energy Information Administration (EIA) for newly constructed utility-scale electric generators in the United States, annual capacity-weighted average construction costs for solar photovoltaic systems and onshore wind turbines have continued to decrease. Natural gas generator costs also decreased slightly in 2018.

From 2013 to 2018, costs for solar fell 50%, costs for wind fell 27%, and costs for natural gas fell 13%. Together, these three generation technologies accounted for more than 98% of total capacity added to the electricity grid in the United States in 2018. Investment in U.S. electric-generating capacity in 2018 increased by 9.3% from 2017, driven by natural gas capacity additions.

Solar
The average construction cost for solar photovoltaic generators is higher than wind and natural gas generators on a dollar-per-kilowatt basis, although the gap is narrowing as the cost of solar falls rapidly. From 2017 to 2018, the average construction cost of solar in the United States fell 21% to $1,848 per kilowatt (kW). The decrease was driven by falling costs for crystalline silicon fixed-tilt panels, which were at their lowest average construction cost of $1,767 per kW in 2018.

Crystalline silicon fixed-tilt panels—which accounted for more than one-third of the solar capacity added in the United States in 2018, at 1.7 gigawatts (GW)—had the second-highest share of solar capacity additions by technology. Crystalline silicon axis-based tracking panels had the highest share, with 2.0 GW (41% of total solar capacity additions) of added generating capacity at an average cost of $1,834 per kW.

average construction costs for solar photovoltaic electricity generators

Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory

Wind
Total U.S. wind capacity additions increased 18% from 2017 to 2018 as the average construction cost for wind turbines dropped 16% to $1,382 per kW. All wind farm size classes had lower average construction costs in 2018. The largest decreases were at wind farms with 1 megawatt (MW) to 25 MW of capacity; construction costs at these farms decreased by 22.6% to $1,790 per kW.

average construction costs for wind farms

Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory

Natural gas
Compared with other generation technologies, natural gas technologies received the highest U.S. investment in 2018, accounting for 46% of total capacity additions for all energy sources. Growth in natural gas electric-generating capacity was led by significant additions in new capacity from combined-cycle facilities, which almost doubled the previous year’s additions for that technology. Combined-cycle technology construction costs dropped by 4% in 2018 to $858 per kW.

average construction costs for natural gas-fired electricity generators

Source: U.S. Energy Information Administration, Electric Generator Construction Costs and Annual Electric Generator Inventory

September, 17 2020
Fossil fuels account for the largest share of U.S. energy production and consumption

Fossil fuels, or energy sources formed in the Earth’s crust from decayed organic material, including petroleum, natural gas, and coal, continue to account for the largest share of energy production and consumption in the United States. In 2019, 80% of domestic energy production was from fossil fuels, and 80% of domestic energy consumption originated from fossil fuels.

The U.S. Energy Information Administration (EIA) publishes the U.S. total energy flow diagram to visualize U.S. energy from primary energy supply (production and imports) to disposition (consumption, exports, and net stock additions). In this diagram, losses that take place when primary energy sources are converted into electricity are allocated proportionally to the end-use sectors. The result is a visualization that associates the primary energy consumed to generate electricity with the end-use sectors of the retail electricity sales customers, even though the amount of electric energy end users directly consumed was significantly less.

U.S. primary energy production by source

Source: U.S. Energy Information Administration, Monthly Energy Review

The share of U.S. total energy production from fossil fuels peaked in 1966 at 93%. Total fossil fuel production has continued to rise, but production has also risen for non-fossil fuel sources such as nuclear power and renewables. As a result, fossil fuels have accounted for about 80% of U.S. energy production in the past decade.

Since 2008, U.S. production of crude oil, dry natural gas, and natural gas plant liquids (NGPL) has increased by 15 quadrillion British thermal units (quads), 14 quads, and 4 quads, respectively. These increases have more than offset decreasing coal production, which has fallen 10 quads since its peak in 2008.

U.S. primary energy overview and net imports share of consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

In 2019, U.S. energy production exceeded energy consumption for the first time since 1957, and U.S. energy exports exceeded energy imports for the first time since 1952. U.S. energy net imports as a share of consumption peaked in 2005 at 30%. Although energy net imports fell below zero in 2019, many regions of the United States still import significant amounts of energy.

Most U.S. energy trade is from petroleum (crude oil and petroleum products), which accounted for 69% of energy exports and 86% of energy imports in 2019. Much of the imported crude oil is processed by U.S. refineries and is then exported as petroleum products. Petroleum products accounted for 42% of total U.S. energy exports in 2019.

U.S. primary energy consumption by source

Source: U.S. Energy Information Administration, Monthly Energy Review

The share of U.S. total energy consumption that originated from fossil fuels has fallen from its peak of 94% in 1966 to 80% in 2019. The total amount of fossil fuels consumed in the United States has also fallen from its peak of 86 quads in 2007. Since then, coal consumption has decreased by 11 quads. In 2019, renewable energy consumption in the United States surpassed coal consumption for the first time. The decrease in coal consumption, along with a 3-quad decrease in petroleum consumption, more than offset an 8-quad increase in natural gas consumption.

EIA previously published articles explaining the energy flows of petroleum, natural gas, coal, and electricity. More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.

Principal contributor: Bill Sanchez

September, 15 2020
Nord Stream 2: Democratic Ideals or Business Reality

It was an innocuous set of words published in a newspaper in Germany on Sunday. “I hope the Russian do not force us to change our position on Nord Stream 2”, the German Foreign Minister Heiko Maas was quoted as saying. A day after that, Angela Merkel also issued a single sentence: “The German Chancellor agrees with the Foreign Minister’s comments from the weekend.” Simple words with a bold message. And potentially devastating consequences.

The incident that hardened the hearts of Germany , which had become increasingly isolated over the issue of the Nord Stream 2 natural gas pipeline that connects Russia to Germany through the Baltic Sea, was the hospitalisation of Russian opposition leader Alexei Navalny. Airlifted to Berlin following a medically-induced coma, German doctors concluded that Navalny, who is no stranger to intimidation tactics by the Putin government, was the victim of the Novichok nerve agent. If that name sounds familiar, that’s because it made headlines in 2018 over the attempted assassination of former Russian spy Sergei Skripal and his daughter Yulia in Salisbury, UK. A lethal nerve agent developed in the 1970s in Soviet Russia, Novichok is among the deadliest poisons ever developed and is banned under the Organisation for the Prohibition of Chemical Weapons. The Kremlin, predictably, denies involvement in the alleged poisoning, dismissing the German allegations as untrue.

That this could be the straw that broke the Nord Stream 2 back is perhaps surprising. The Nord Stream 2 natural gas pipeline has survived many obstacles. Many, many obstacles. The sequel to the original 1,222km Nord Stream that was inaugurated in November 2011, Nord Stream 2 will add 1,230km more pipeline between Vyborg in Russia and Lubin in Germany, with nearly all of the entire 2,452km length already being laid. Championed by former German Chancellor Gerhard Schröder and inherited by Merkel, the Nord Stream pipelines were developed to meet Germany’s growing energy demand, as it moved away from burning coal and nuclear fission. However, it has attracted criticism from many quarters. From Germany’s neighbours including Poland, Denmark and Estonia concerned over the pipeline that passes through their waters. From the EU, concerned about making Germany too energy dependent from a ‘politically unreliable’ country. From the US, which has threatened and, indeed, imposed sanctions on companies involved in the project. Some would argue that the vociferous US involvement, championed by President Donald Trump is self-serving, meant to allow US energy exports to muscle in, but it still fits neatly into Germany’s Russian dependence issue.

Throughout all this drama, Angela Merkel has stood firm. She, and her centre-right party CDU, have supported Nord Stream somewhat unenthusiastically with the primary concerns being the business element. It will unravel Germany’s plans to become a natural gas hub, as it tries to drive an EU movement towards cleaner energy. Many of Germany’s largest companies,  include petrochemicals giant BASF and its energy arm Wintershall are also heavily invested in Nord Stream and the raw gas it will bring. It would also be a reputational risk to pull the plug on a project that is almost complete and set to be launched by the year’s end, and still leaves the critical question on how Germany will be able to address its energy deficit.

The business argument has overridden political concerns so far. But now a moral imperative has arisen through the attempted murder of Alexei Navalny, with his subsequent medical treatment in Berlin. This resonates in Germany particularly, since the country understands the historical consequences of authoritarian governments and the dangers it bring. The shifting of the political landscape, especially the rise of the Green Party has triggered a ferocious debate with high-ranking politicians from both the left and right calling for the project to be scrapped. Some are even arguing that Nord Stream 2 gas supply is no longer necessary, as the country’s energy requirements are now fundamentally shifting in a post-Covid 19 world.

If, and that is a very big if, the Nord Stream 2 is scrapped, that is at least US$9.4 billion down the drain and plenty more in collateral damage from peripheral activities. It will rock the boat when the usual Merkel instinct is to steady it. But the furore over an attempted assassination by one of the world’s deadliest methods no less, might be a stand that Germany is willing to take. After all, it knows first-hand the effects of an iron fist. Berlin has so far stood alone in advancing Nord Stream 2, even after the chorus of critics surrounding it grow louder and louder. If it were to kill the project, Germany could find plenty of supporters for that move and would be more than happy to offer themselves up as a role to scupper this ship. The options are varied, but one question remains that will influence the whole issue: how is Angela Merkel willing to go to take a stand over democratic ideals or business reality?

Market Outlook:

  • Crude price trading range: Brent – US$39-41/b, WTI – US$36-38/b
  • A second global acceleration in Covid-19 cases is hampering hopes that the worldwide economy will be able to return to normality by the year’s end, delaying the time it will take for crude demand to return to its pre-crisis level
  • With the summer driving season in the northern hemisphere coming to a close, US crude stockpiles are rising, driving down prices even though the US EIA raised its forecasts for 2020 to US$38.99 for WTI and US$41.90 for Brent
  • The downturn in prices was also driven by Saudi Arabia cutting its crude pricing for October sales by a larger-than-expected amount, especially for Asian shipments

END OF ARTICLE

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September, 15 2020