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Kazakhstan, an oil producer since 1911, has the second-largest oil reserves and the second-largest oil production among the former Soviet republics after Russia.

Kazakhstan is a major oil producer. The country’s estimated total petroleum and other liquids production was 1.698 million barrels per day (b/d) in 2016. The key to its continued growth in liquids production from this level is the development of its giant Tengiz, Karachaganak, and Kashagan fields. Development of additional export capacity will also be necessary for production growth.

Although Kazakhstan became an oil producer in 1911, its production did not increase to a meaningful level until the 1960s and 1970s, when production plateaued at nearly 500,000 b/d, a pre-Soviet independence record production level. Since the mid-1990s, and with the help of major international oil companies, Kazakhstan's production first exceeded 1 million b/d in 2003.

Oil field development in Kazakhstan reached two milestones in 2016. In October 2016, the giant Kashagan field resumed production after years of delays. Kashagan is expected to produce 370,000 b/d of liquids at full capacity. Additionally, in July 2016, The Tengizchevroil consortium decided to proceed with expansion plans that should increase liquids production at the Tengiz project by about 260,000 b/d beginning in 2022.

Kazakhstan is landlocked and is far from international oil markets. The lack of access to the open ocean makes the country dependent mainly on pipelines to transport its hydrocarbons to world markets. Kazakhstan is also a transit country for oil and natural gas pipeline exports to China.

Kazakhstan consumed 2.66 quadrillion British thermal units (Btu) of energy in 2014, with coal accounting for the largest share of energy consumed (63%), followed by petroleum and natural gas (18% and 16%, respectively) (Figure 2).

Kazakhstan is a Caspian Sea littoral state. The legal status of the Caspian area remains unresolved, mainly driven by a lack of agreement on whether the Caspian is a sea or a lake. Until all states agree on a definition, the legal status of the area will remain unresolved.

uploads1494583497760-energy_consumption.pngOil field development in Kazakhstan reached two milestones in 2016. In October 2016, Kashagan field resumed production after years of delays. In July 2016, the Tengizchevroil consortium made a final investment decision on a project to increase liquids production by about 260,000 b/d.

According to the Oil & Gas Journal (OGJ), Kazakhstan had proved crude oil reserves of 30 billion barrels as of January 2017–the second–largest endowment in Eurasia after Russia, and the twelfth largest in the world, just behind the United States.1 Kazakhstan's current oil production (Figure 3) has been dominated by two giant onshore fields in the northwest of the country: Tengiz and Karachaganak, which together produced about half of Kazakhstan’s total petroleum liquids output in 2016. The offshore Kashagan field, in Kazakhstan’s part of the Caspian Sea, started production in October 2016. At full capacity, Kashagan will join Tengiz and Karachaganak as the three largest producing fields in Kazakhstan. Additionally, in July 2016, The Tengizchevroil consortium decided to proceed with expansion plans that should increase liquids production at the Tengiz project by about 260,000 b/d beginning in 2022.

Kazakhstan's petroleum and other liquids production and consumption

Sector organization

The Ministry of Energy oversees the oil and natural gas industry in Kazakhstan. In August 2014, Kazakhstan’s president, Nursultan Nazarbayev, announced an extensive government reorganization with the intention of creating a more compact and effective government. The number of ministries in the government was reduced from 17 to 12, and the Ministry of Energy was created to absorb the functions of the Ministry of Oil and Gas and parts of the functions of the Ministry for Industry and New Technologies and the Ministry for Environment and Water Resources.2

The national oil and natural gas company, KazMunaiGaz (KMG), represents the state's interests in Kazakhstan's oil and gas industry. KMG was created in 2002 and holds equity interests in Karachaganak (10%), Kashagan (16.88%), and Tengiz (20%), as well as interests ranging between 33% and 100% in many other production projects.3

Kazakhstan's Law on Subsoil and Subsoil Use (Subsoil Use Law) governs investments in the oil and natural gas industries. The Subsoil Use Law has been amended several times, most notably in 2005, 2007, 2010, and 2014. Among other provisions, the Subsoil Use Law along with the December 2009 Local Content Law established strict local content requirements for oil and gas contracts. The Subsoil Use Law also established the government’s right to preempt any sale of oil and gas assets. In 2013 Kazakhstan preempted ConocoPhillips sale of its 8.4% stake in the Kashagan project to India’s ONGC.

The preemption did not affect Conoco’s proceeds from the sale, but rather than going to ONGC, the stake was purchased by KMG before being resold to China’s CNPC.4

The government announced the re-introduction of oil export duties in August 2010, increasing the duty in subsequent years as oil prices climbed, and reducing the oil duty several times since 2014 when oil prices declined sharply. Export duties were first introduced in 2008 and then were suspended in January 2009. Export duties affect all oil exporters operating in Kazakhstan, with the exceptions of those that include a tax stabilization clause in their contracts.

Production

In the 1970s, several large discoveries were made in presalt reservoirs, including Karachaganak and Tengiz. However, the development of these fields was not possible at the time because of the technical challenges of developing the deep, high-pressure reservoirs. Since international oil companies began to participate in Kazakhstan's petroleum sector and as presalt deposits became technically and commercially viable, these fields have become the foundation of the country's petroleum liquids production.

Although Kazakhstan is the second-largest liquid fuels producer among Former Soviet Union republics, its future as a producer of petroleum liquids depends on the development and expansion of its three largest projects: Karachaganak, Kashagan, and Tengiz (Table 1).5Kazakhstan’s two largest projects, Tengiz and Karachaganak, accounted for 50% (Tengiz 35%, Karachaganak 15%) of the country's production in 2016, according to data published by Energy Intelligence.6 When production at Kashagan (which started in October 2016) reaches full capacity, the combined output of all three projects is likely to account for at least 60% of Kazakhstan’s total production.

In July 2016, the Tengiz partners made a final investment decision to proceed with the Future Growth Project. This expansion project is expected to be completed by 2022, bringing about 260,000 b/d of additional liquids production from Tengiz. An expansion project has also been proposed for the Karachaganak field, but it is at a less-advanced stage of planning.

The Kashagan field, the largest known oil field outside the Middle East and the fifth largest in the world in terms of reserves, is located off the northern shore of the Caspian Sea near the city of Atyrau, Kazakhstan. Kashagan's recoverable reserves are estimated at 7 to 13 billion barrels of crude oil. On September 11, 2013, production from the super-giant field commenced, eight years after the originally scheduled startup date. In October 2013, just a few weeks after production began, production had to be halted because of leaks in the pipeline that transports natural gas from the field to shore. Production restarted in October 2016, and by January 2017, the field was producing more than 100,000 b/d of liquids. Full capacity for the first phase of development is production of 370,000 b/d.

Many of the repeated delays at Kashagan were the result of the field's adverse operating environment and complexity, resulting in significant cost overruns. The Kashagan reservoir is located more than 13,000 feet below the seabed and is under very high pressure (770 pounds per square inch). The reservoir contains high levels of hydrogen sulfide. Hydrogen sulfide is both highly toxic and highly corrosive and has been blamed for the pipeline leaks. In addition, conventional drilling and production technologies such as fixed or floating platforms cannot be used because of the shallow water and cold climate. Instead, offshore facilities are installed on artificial islands (drilling and hub islands) that house drilling and processing equipment. The processing facilities separate recovered liquids from the gas, reinject a portion of the gas, and send the liquids and the remainder of the gas to shore for further processing. Before production could restart, the pipelines connecting the field with the onshore processing facilities had to be replaced using higher-grade materials that are more resistant to corrosion.

Table 1. Kazakhstan's major oil and gas fieldsField nameCompaniesStart yearLiquids productionNatural gas productionTengiz (& Korolev)Chevron, ExxonMobil, KazMunaiGaz, LukArco (Lukoil and BP)1991570,000 thousand bbl/d total liquids production in 2016
Expansion project to add 260,000 b/d of crude production beginning in 2022274 Bcf drymarketed gas production in 2013KarachaganakBG, Eni, Chevron, Lukoil, KazMunaiGaz1984206,000 b/d total liquids production in 2016
An expansion project is under consideration, but potential production volumes are uncertainAbout 300 Bcf wet marketed gas production in 2016KashaganKazMunaiGaz, Eni, ExxonMobil, Shell, Total, China National Petroleum Corporation, Inpex2016370,000 b/d liquids processing capacity with current developmentOver 100 Bcf gas production capacitySource: U.S. Energy Information Administration based on data from TengizChevroil, Chevron, Karachaganak Petroleum Operating (KPO), and Eni

Oil exports

Kazakhstan is an exporter of light, sweet crude oil. In 2016, Kazakhstan exported about 1.3 million b/d of crude oil and condensate, according to EIA estimates based on data from Global Trade Tracker and Lloyd's List Intelligence (APEX) (Figure 4).7 Most of Kazakhstan’s crude exports travel around or across the Caspian Sea to European markets. An additional 5% of Kazakhstan’s crude oil exports flowed east via a pipeline to China. A significant portion of Kazakhstan’s exports transit Italy and the Netherlands, making it difficult to determine where this crude oil ends up because Kazakhstan reports these volumes as having been delivered to the transit countries.

Export routes

Kazakhstan's pipeline system is operated by the state-run KazTransOil, a subsidiary of KazMunaiGas, which runs approximately 3,400 miles of pipelines. Because of Kazakhstan’s landlocked location and the continued use of Soviet-era infrastructure, much of Kazakhstan’s oil and gas export infrastructure is integrated with major Caspian oil and natural gas export routes that interlink the region. Since independence, Kazakhstan has successfully expanded and diversified its export capabilities. Major crude oil export pipelines include the Caspian Pipeline Consortium pipeline to the Black Sea port of Novorossiysk, the Kazakhstan-China pipeline, and the Uzen-Atyrau-Samara pipeline to Russia (Figure 5).

Kazakhstan also exports crude oil via the Caspian Sea and via rail. Oil is loaded onto tankers or barges at Kazakhstan’s port of Aktau or the smaller Atyrau port and then shipped across the Caspian Sea, where it is loaded onto the Baku-Tbilisi-Ceyhan pipeline or the Northern Route pipeline (Baku-Novorossiysk) for onward transport, mainly to Europe. Additionally, Kazakhstan has an extensive rail network, which it uses to transport liquid fuels both for domestic consumption and for exports. Continued expansion and diversification of Kazakhstan’s petroleum liquids transport capacity, particularly export capacity, is key to its future ability to increase production.

Another potential export route for Caspian crude oil is via swaps with Iran. For years, Kazakhstan and other Central Asian countries delivered their crude oil to Iran’s Caspian Sea port of Neka. From there the crude oil was delivered to refineries in Tehran and Tabriz, with the refined products distributed and consumed in northern Iran. In exchange, Iran exported equal volumes of crude out of its Persian Gulf ports on behalf of Kazakhstan. Swap volumes have varied over the years, with little to no crude swapped since 2011. Sanctions against Iran reportedly complicated swap arrangements, especially the marketing of the crude oil exported in the Persian Gulf, which had been done by the Iranians. Also complicating the swap arrangements was Iran’s desire to raise the fee it charged Kazakhstan for each barrel of crude swapped. Since at least late 2013, Iran and Kazakhstan have been discussing resumption of the swap arrangement and have periodically announced their intentions to resume swaps, but no swaps had occurred as of the end of 2016.

Kazakhstan's crude exports by destination, 2016

Figure 5. Kazakhstan map of major crude oil pipelines

Map of major Caspian oil and natural gas export routes

Oil grades

Kazakhstan’s main export oil grade is the CPC Blend. CPC Blend is a very light (45.3° API), sweet crude (0.56% sulfur)8 that is valued for its high yield of gasoline and light distillates. Production from the Tengiz field accounts for about 60% of the CPC blend. Other components include production from Karachaganak, Kashagan, and Kumkol fields, some Russian grades such as Siberian Light, along with a variety of other Russian and Kazakh grades.

Smaller volumes of many of the components of CPC Blend are also marketed separately as distinct crude oil grades. However, with the recent expansion of the CPC pipeline, the volumes of crude oil marketed separately have declined.

Refining

Kazakhstan had three major crude oil refineries with crude oil distillation capacity of 340,000 b/d as of January 1, 2017, according to OGJ.9 The three major oil refineries in Kazakhstan are: Pavlodar, Atyrau, and Shymkent. The Pavlodar refinery is in north-central Kazakhstan and is supplied mainly by a crude oil pipeline from western Siberia, because Russian supplies are well-placed geographically to serve that refinery. The Atyrau refinery uses only domestic crude oil from northwest Kazakhstan, and the Shymkent refinery currently uses crude from the oil fields at Kumkol and the nearby area in central Kazakhstan. There is also a smaller refinery at Aktau that processes heavy crude oil produced at a nearby field to make bitumen for road construction.10

The three main refineries meet approximately 70% of Kazakhstan’s gasoline and diesel demand, with most of the remaining demand met by imports from Russia. Upgrading projects were underway in early 2017 at all three refineries and are expected to be completed in late 2017 or early 2018. The upgrades will allow the three plants to produce fewer heavy products and more high-quality transportation fuels. With these upgrades, Kazakhstan aims to meet all domestic demand for gasoline and diesel production by 2019.11

Natural gas

Kazakhstan’s largest petroleum liquids fields also contain substantial volumes of natural gas, much of which is reinjected into oil wells to improve oil recovery rates.

OGJ estimated Kazakhstan’s proven natural gas reserves at 85 trillion cubic feet (Tcf) as of January 1, 2017.12 Most of Kazakhstan’s natural gas reserves are in crude oil or condensate-rich fields. The two largest petroleum liquids fields, Karachaganak and Tengiz, are also the two largest natural gas fields.

Production

Over the past decade, annual gross natural gas production almost doubled, from 0.8 Tcf in 2005 to 1.5 Tcf in 2015. Much of Kazakhstan’s gross natural gas production is reinjected (more than 30% in 2015) to increase oil production. Much of the natural gas produced at Tengiz and Kashagan is high in sulfur, and therefore requires special handling and is more costly to process.

In 2016, the Karachaganak and Tengiz fields combined accounted for about 70% of Kazakhstan’s natural gas production.13 The Tengiz project includes a natural gas processing plant, which according to Chevron produced 274 billion cubic feet (Bcf) of dry marketed natural gas in 2016 that was sold to local consumers.14 The Karachaganak project has insufficient gas processing capacity. Most of the raw marketed production from the Karachaganak field must be exported to Russia to be processed at a gas processing plant in Orenberg.

Production restarted at the Kashagan field in October 2016. When the project reaches full capacity, it is expected to produce about 100 Bcf of natural gas per year for domestic consumption, with additional produced gas reinjected into the reservoir to boost liquids recovery.

Consumption, imports, and exports

Kazakhstan has two major export pipelines for natural gas (Figure 6). The Central Asia Centre pipeline (CAC), which traverses the western edge of Kazakhstan on its way to Russia and points further west, and the Turkmenistan-China pipeline, which traverses the southern edge of the country on its way to China. Both pipelines are part of the regional Caspian export infrastructure and mainly carry natural gas exports from Turkmenistan, along with smaller but still significant volumes of exports from Kazakhstan and Uzbekistan. The CAC pipeline also serves local natural gas demand in western Kazakhstan, including northwestern Kazakhstan where most of the country’s production is located.

A third major international pipeline, the Bukhara-Tashkent-Bishkek-Almaty pipeline, serves local demand in southern Kazakhstan. Two of Kazakhstan’s three underground natural gas storage facilities are located along this pipeline.

Natural gas production in Kazakhstan is concentrated in the northwest and, until recently, has not been connected to population centers in the south, north, center, and east. Prior to 2016, consumers in southern Kazakhstan were supplied with imported natural gas from Turkmenistan or Uzbekistan. However, in November 2015, KazTransGas, the state-owned natural gas pipeline operator, completed the final link in the new Beinu-Bozoi-Shymkent pipeline. This pipeline has allowed Kazakhstan to gasify communities along the route of the pipeline that previously had no access to gas. It has also connected the natural gas fields and infrastructure in the northwest of the country to the population centers in the south of the country, replacing imported natural gas in those markets with domestically produced gas. Completing this link has also connected Kazakshtan’s producing regions with the natural gas pipeline to China, allowing production from northwestern Kazakhstan to be exported to China. Kazakhstan has also discussed the possibility of using this infrastructure to transit Russian natural gas to China.

Plans for gasifying other parts of the country and connecting them to the existing infrastructure in the West and South are more uncertain. The vast distances and relatively low population density in the north, center, and east make the economics challenging for any potential gas pipeline projects to serve those regions. Kazakhstan contracted to import 5,000 metric tons of liquefied natural gas (LNG) in 2017 (about 0.2 Bcf of gaseous natural gas) from Russia by road to Astana, Kazakhstan’s capital, and other cities in the north of the country. Kazakhstan’s coal basins, which lie in the north and center of the country, could also be a source of natural gas supplies for areas of the country that are far from existing natural gas production and infrastructure. Kazakhstan has been exploring the potential to produce and market methane from coal mines and coal beds.

Figure 6. Kazakhstan map of major natural gas pipelines

Figure 6. Kazakhstan map of major natural gas pipelines

Coal

In 2014, coal accounted for 56% of Kazakhstan’s total energy consumption.

With 28,225 million short tons (MMst) of total recoverable coal reserves as of 2014, Kazakhstan is in the top ten countries in the world in terms of coal reserves, coal production, and coal exports. It is also in the top fifteen countries in the world in terms of coal consumption. Despite being among the top coal countries, Kazakhstan is a relatively small contributor to global coal volumes. The top four countries globally account for disproportionate shares of total global coal reserves, production, consumption, and exports (between 65% and 75% combined), while Kazakhstan accounts for between 1% and 4%.

About a quarter of Kazakhstan’s coal production is exported, with most going to Russia. Virtually all of Kazakhstan’s coal production and exports consist of steam coal, which is suitable for burning in electric power plants or in other applications to generate steam and heat. Kazakhstan also produces smaller quantities of metallurgical coal that are consumed domestically. Kazakhstan is rich in a variety of minerals, with mineral and coal deposits concentrated in the north and center of the country. Coal is a major energy source for the mining and smelting industries and for the electricity sector in Kazakhstan.

Electricity

Most of Kazakhstan's power generation comes from coal-fired power plants, concentrated in the north of the country near the coal-producing regions.

Kazakhstan's total installed generating capacity was 22.1 gigawatts (GW) as of 2017.15Kazakhstan's total generation in 2016 was 94.1 billion kilowatthours (BkWh) of electricity—of which 87% came from fossil fuel-fired plants, 12% came from hydropower plants, and less than 1% came from solar and wind installations.16

Kazakhstan's only nuclear power plant, a BN-350 nuclear reactor at Aktau, was shut down in 1999. Kazakhstan has some of the largest uranium deposits in the world and is the world's largest uranium producer.17 Although plans have long existed to build additional nuclear power plants, there has been little progress on constructing these units.

Kazakhstan's national grid is operated by the Kazakhstan's Electricity Grid Operating Company, a state-owned company, which is responsible for electric transmission and network management. A number of medium and small regional electricity companies handle distribution, some of which are privately owned. The electricity transmission and distribution sectors are considered to be natural monopolies and are regulated by the government. However, wholesale generation of power is considered to be a competitive market with most generation assets owned by private enterprises.


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Nigeria’s Energy Focus Must Change From Crude Oil to Gas – Dr Chukwueloka Umeh

According to the Nigeria National Petroleum Corporation (NNPC), Nigeria has the world’s 9th largest natural gas reserves (192 TCF of gas reserves). As at 2018, Nigeria exported over 1tcf of gas as Liquefied Natural Gas (LNG) to several countries. However domestically, we produce less than 4,000MW of power for over 180million people.

Think about this – imagine every Nigerian holding a 20W light bulb, that’s how much power we generate in Nigeria. In comparison, South Africa generates 42,000MW of power for a population of 57 million. We have the capacity to produce over 2 million Metric Tonnes of fertilizer (primarily urea) per year but we still import fertilizer. The Federal Government’s initiative to rejuvenate the agriculture sector is definitely the right thing to do for our economy, but fertilizer must be readily available to support the industry. Why do we import fertilizer when we have so much gas?

I could go on and on with these statistics, but you can see where I’m going with this so I won’t belabor the point. I will leave you with this mental image: imagine a man that lives with his family on the banks of a river that has fresh, clean water. Rather than collect and use this water directly from the river, he treks over 20km each day to buy bottled water from a company that collects the same water, bottles it and sells to him at a profit. This is the tragedy on Nigeria and it should make us all very sad.

Several indigenous companies like Nestoil were born and grown by the opportunities created by the local and international oil majors – NNPC and its subsidiaries – NGC, NAPIMS, Shell, Mobil, Agip, NDPHC. Nestoil’s main focus is the Engineering Procurement Construction and Commissioning of oil and gas pipelines and flowstations, essentially, infrastructure that supports upstream companies to produce and transport oil and natural gas, as well as and downstream companies to store and move their product. In our 28 years of doing business, we have built over 300km of pipelines of various sizes through the harshest terrain, ranging from dry land to seasonal swamp, to pure swamps, as well as some of the toughest and most volatile and hostile communities in Nigeria. I would be remiss if I do not use this opportunity to say a big thank you to those companies that gave us the opportunity to serve you. The over 2,000 direct staff and over 50,000 indirect staff we employ thank you. We are very grateful for the past opportunities given to us, and look forward to future opportunities that we can get.

CLICK HERE TO READ MORE

July, 19 2019
Your Weekly Update: 15 - 19 July 2019

Market Watch 

Headline crude prices for the week beginning 15 July 2019 – Brent: US$66/b; WTI: US$59/b

  • Global oil prices gained as US crude inventories shrank more than expected and a hurricane in the Gulf of Mexico threatened American offshore production
  • Tropical Storm Barry – which became a hurricane on landfall in Louisiana – was in the path of up to a third of Gulf of Mexico crude output, prompting producers to shut down most of their operations; resumption of normal service has begun
  • At the same time, US crude oil stockpiles fell by almost 10 million barrels, far more than expected, with US refineries ramping up production ahead of summer demand to add some bullishness to the market
  • The ongoing tensions between the US and Iran have not escalated further yet, but Iran has vowed to continue retaliating against the British seizure of its crude tanker in the Mediterranean off Gibraltar
  • These factors have been enough to keep current crude prices trending higher, but oil producing club OPEC warns that the market will swing back into surplus next year, estimating that it is currently producing 560,000 b/d more than will be needed without even factoring in rising US shale production
  • In Venezuela, where oil production has been crippled by sanctions, Chevron is reportedly seeking a waiver to continue operating in the country after the current waiver expires in July 27
  • The US active oil and gas rig count fell once again, shedding a net five rigs (including 4 oil rigs) as merely stable prices reduced the appetite for investment; the total active rig count is now 958, 96 sites lower than this period last year
  • As the threat of Tropical Storm Barry abated, crude prices fell back in line. Without any further disruptions on the horizon, Brent should trend in the US$62-64/b range and WTI in the US$55-57 range


Headlines of the week

Upstream

  • Norway’s Equinor has bought a 16% stake in Swedish upstream firm Lundin Petroleum for US$650 million, which gains it an additional 2.6% interest in the giant Johan Sverdrup oil field bringing Equinor’s total stake up to 42.6%
  • Inpex has picked up the exploration permit for Block AC/P66 in Australia’s Northwest Shelf, which lies in the vicinity of existing promising oil fields
  • US independent Callon Petroleum Company has acquired Carrizo Oil & Gas for US$3.2 billion, deepening its holdings in the Permian and Eagle Ford shale basins, including 90,000 net acres in the prolific Delaware Basin
  • Total has agreed to divest several of its non-core assets in the UK – covering the Balloch, Dumbarton, Lochranza, Drumtochty, Flyndre, Affleck, Cawdow, GoldenEagle, Scott and Telford fields – to Petrogas NEO for US$635 million
  • CNOOC and Sinopec has signed a new agreement to collaborate on exploration activities in the Bohai Basin, Beibu Gulf, North Jiangsu and South Yellow Sea
  • Murphy Oil has completed the sale of its Malaysian upstream assets to a unit of Thailand’s PTTEP for US$2.035 billion for five offshore projects in Sabah
  • Seven upstream discoveries were made in Colombia in 2Q19, making it the market with the most discoveries during the period, leading India, Russia and Pakistan which each made three new oil and gas finds
  • Turkey has vowed to continue drilling offshore Cyprus unless a cooperation proposal between Turkish and Greek Cypriots is accepted
  • Encana is reportedly selling off its assets in eastern Oklahoma’s Arkoma Basin for US$165 million in cash to an undisclosed buyer
  • Sinopec is hunting for partners or buyers for its Buck Lake assets in Alberta’s Duvernay shale basin in Canada, to reduce its current full ownership

Midstream/Downstream

  • The Governor of Pennsylvania Tom Wolf has ruled out using state funds to save the Philadelphia Energy Solutions refinery after it was shuttered following a massive fire that took out the entire site last month
  • Blackouts hit Venezuela’s Amuay and Cardon refineries, bringing the 955,000 b/d Paraguana refining Center to a complete halt on total lack of power
  • Chevron Phillips Chemical (CP Chem) and Qatar Petroleum have agreed to develop a new 2 mtpa petrochemical complex on the US Gulf Coast, with the US Gulf Coast II Petrochemical Project drawing on NGLs from the Permian
  • Marathon Petroleum will shut down the gasoline FCCU unit at its 585,000 b/d Galveston Bay Refinery in Texas for up to 8 weeks for repairs

Natural Gas/LNG

  • Total has agreed to buy NG from Tellurian’s Driftwood LNG facility in Lake Charles, Louisiana in two separate deals – 1 million tons per annum for Total Gas & Power North America and 1.5 mtpa for Total Gas & Power – as well as invest US$500 million in Driftwood Holdings LP
  • Mozambique has put on hold plans to raise funds for its stake in the Anadarko-led Mozambique LNG project, citing current bad market conditions
  • ExxonMobil and Lucid Energy Group have agreed to collaborate on a long-term natural gas gathering and processing project, bringing natural gas from New Mexico’s Delaware Basin to the South Carlsbad gas processing system before being delivered to ExxonMobil’s downstream facilities in the US Gulf Coast
July, 19 2019
Iran drives unplanned OPEC crude oil production outage to highest levels since late 2015

Unplanned crude oil production outages for the Organization of the Petroleum Exporting Countries (OPEC) averaged 2.5 million barrels per day (b/d) in the first half of 2019, the highest six-month average since the end of 2015. EIA estimates that in June, Iran alone accounted for more than 60% (1.7 million b/d) of all OPEC unplanned outages.

EIA differentiates among declines in production resulting from unplanned production outages, permanent losses of production capacity, and voluntary production cutbacks for OPEC members. Only the first of those categories is included in the historical unplanned production outage estimates that EIA publishes in its monthly Short-Term Energy Outlook (STEO).

Unplanned production outages include, but are not limited to, sanctions, armed conflicts, political disputes, labor actions, natural disasters, and unplanned maintenance. Unplanned outages can be short-lived or last for a number of years, but as long as the production capacity is not lost, EIA tracks these disruptions as outages rather than lost capacity.

Loss of production capacity includes natural capacity declines and declines resulting from irreparable damage that are unlikely to return within one year. This lost capacity cannot contribute to global supply without significant investment and lead time.

Voluntary cutbacks are associated with OPEC production agreements and only apply to OPEC members. Voluntary cutbacks count toward the country’s spare capacity but are not counted as unplanned production outages.

EIA defines spare crude oil production capacity—which only applies to OPEC members adhering to OPEC production agreements—as potential oil production that could be brought online within 30 days and sustained for at least 90 days, consistent with sound business practices. EIA does not include unplanned crude oil production outages in its assessment of spare production capacity.

As an example, EIA considers Iranian production declines that result from U.S. sanctions to be unplanned production outages, making Iran a significant contributor to the total OPEC unplanned crude oil production outages. During the fourth quarter of 2015, before the Joint Comprehensive Plan of Action became effective in January 2016, EIA estimated that an average 800,000 b/d of Iranian production was disrupted. In the first quarter of 2019, the first full quarter since U.S. sanctions on Iran were re-imposed in November 2018, Iranian disruptions averaged 1.2 million b/d.

Another long-term contributor to EIA’s estimate of OPEC unplanned crude oil production outages is the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia. Production halted there in 2014 because of a political dispute between the two countries. EIA attributes half of the PNZ’s estimated 500,000 b/d production capacity to each country.

In the July 2019 STEO, EIA only considered about 100,000 b/d of Venezuela’s 130,000 b/d production decline from January to February as an unplanned crude oil production outage. After a series of ongoing nationwide power outages in Venezuela that began on March 7 and cut electricity to the country's oil-producing areas, EIA estimates that PdVSA, Venezuela’s national oil company, could not restart the disrupted production because of deteriorating infrastructure, and the previously disrupted 100,000 b/d became lost capacity.

July, 18 2019