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The United Kingdom (UK) is the second-largest producer of oil and the third-largest producer of natural gas in OECD Europe.

United Kingdom (UK) oil and natural gas production have grown on average almost 9% and 4% per year, respectively, from 2014 through 2016. Among European countries in the Organization for Economic Cooperation and Development (OECD), the UK was the second-largest producer of petroleum and other liquids in 2016; only Norway produced more. The UK was the third-largest producer of natural gas in OECD Europe, surpassed only by Norway and the Netherlands. High oil and natural gas prices through late 2014 encouraged high levels of investment in the industry and have led to recent production increases. However, since then prices and investment have declined, and production is likely to return to its long-term declining trend.

The UK is the fifth-largest economy in the world in terms of gross domestic product. Following years as a net exporter of crude oil and natural gas, the UK became a net importer of both fuels in 2004 and 2005, respectively, and in 2013 the UK became a net importer of petroleum products, making it a net importer of all fossil fuels for the first time.

On June 23, 2016, in a general referendum, the UK voted to leave the European Union (EU). Britain's exit from the EU has been commonly termed Brexit. On June 19, 2017, the UK and the EU began negotiating the terms under which the UK would leave the EU. Among the concerns for the oil and natural gas industry are the potential for Brexit to impact tariffs on imports and exports and the potential impact on the employment of EU workers in the UK oil and natural gas industry.[1]

Renewable energy use, particularly in the electric power sector, has more than doubled in the UK over the past decade (2007-16). However, petroleum and natural gas continue to account for most of the UK's energy consumption. In 2016, petroleum and natural gas each accounted for 38% of total energy consumption (Figure 2).[2] The share of coal in total energy consumption in the UK has declined rapidly over the past several years from 19% in 2012 to 6% in 2016.

Figure 2. United Kingdom  total primary energy consumption by source, 2016Figure 1. Map of United Kingdom

Map of United Kingdom

Source: Central Intelligence Agency, The World Factbook

Petroleum and other liquids

The UK's oil production and consumption have been on a long-term declining trend, although since 2014, both have generally been flat or increasing.

Oil consumption in the UK peaked in 1973 at about 2.4 million barrels per day (b/d) before declining to 1.5 million b/d in 1983, and recovering to average 1.8 million b/d from the late 1980s through 2007. Since 2007, consumption has been gradually declining, reaching 1.5 million b/d in both 2013 and 2014. Petroleum and other liquids production peaked in 1999 at slightly less than 3.0 million b/d before declining to 0.9 million b/d in 2014. Since 2014, consumption and production have both been generally flat to increasing (Figure 3). The UK has been a net importer of crude oil since 2005, and in 2013, the country also became a net importer of petroleum products.

Figure 3. United Kingdom petroleum and other liquids production and consumption

Sector organization

The UK government has decreased tax rates for the oil and natural gas sector to encourage investment by making UK projects more competitive.

The UK government does not hold a direct interest in oil production, but the sector remains important to the government because of its contributions to the overall economy. According to the UK's Oil and Gas Authority (OGA), in 2016 the oil and natural gas industry spent nearly 9 billion British pounds sterling (GBP) on capital expenditures (more than US$12 billion) and more than GBP 8 billion on operations (more than US$11 billion).[3] The OGA is a government-owned company charged with both regulating and promoting the oil and natural gas industry in the UK. Its responsibilities include issuing oil and natural gas licenses, collecting data from license holders, and working with the government and private companies to promote investment, collaboration, and efficiency in the industry.

In 2011, the UK government implemented several changes in tax structures and rates that applied to production from the UK continental shelf (UKCS). Collectively, these changes significantly increased tax rates on the oil and natural gas industry in the UK. Higher tax rates, along with high operating and decommissioning costs for fields in the North Sea, made UKCS projects less competitive. A report commissioned by the UK government in 2013 recommended adopting a strategy for Maximizing Economic Recovery (MER) from the UKCS. The government's implementation of the report's recommendations included decreasing the maximum marginal tax rates on profits from oil and natural gas production from 81% to 40%.

Oil and natural gas taxes in the UK have two components, the Ring-Fence Corporation Tax (RFCT), with a maximum rate of 30%, and the Supplementary Charge (SC), with a maximum rate of 10%. Tax rates can be lower after credits for capital investment or other reductions are applied. A third part of oil and natural gas taxes, the Petroleum Revenue Tax (PRT), has been permanently reduced to zero, but companies may still claim losses (such as for decommissioning expenses) against past PRT payments, which can result in a tax refund.[4] These taxes are in addition to the normal direct and indirect taxes that companies pay including employment taxes, value-added taxes (VAT), and customs duties.

For the 2016-17 fiscal year, UK government revenues from the oil and natural gas industry were the lowest since records began in the 1968-69 fiscal year. Revenues from the RFCT and SC amounted to GBP 336 million, but the PRT resulted in a charge to the government of GBP 654 million, which resulted in total net revenues of negative GBP 316 million.[5] However, government revenues from customs duties, VAT, employment, and other taxes not separately reported for the oil and natural gas industry are estimated to have exceeded GBP 1 billion.[6]

Exploration and production

UK total petroleum and other liquids production grew on average almost 9% per year from 2014 through 2016.

Oil production peaked in 1999 at slightly less than 3.0 million b/d after oil companies developed a number of oil fields in the North Sea. After 1999, petroleum and other liquids production in the UK declined at an average annual rate of 8% through 2014, when production fell to 0.9 million b/d. From 2014 through 2016, production grew on average almost 9% per year.[7] Production in 2017 was nearly the same as in 2016.

Much of the increase in production since 2014 is attributable to new fields brought online over the past couple years. Petroleum development projects in the North Sea generally have long lead times, meaning that production from a new field occurs several years after the decision to develop that field. Thus, the recent increases in production are mainly a result of investment decisions made several years ago, when Brent crude oil prices were much higher.

Although production in the UK has not yet responded to lower oil prices, investment in the UK's oil and natural gas industry is declining. This decline will likely lead to lower production in the future.

According to the Oil & Gas Journal (OGJ), the UK had 2.1 billion barrels of proved crude oil reserves as of the end of 2017, almost 20% lower than the level at the end of 2016.[8] Most of the UK's reserves are located offshore on the UKCS, and most of the liquids production occurs in the central and northern sections of the North Sea.

Oil grades

Three main grades of oil are produced in the UK: Flotta, Forties, and Brent blends. They are generally light and sweet, which makes them attractive to foreign buyers. Flotta is the smallest and lowest-quality (36.64° API and 0.66% sulfur) stream produced in the UK. Flotta crude oil is loaded at the Repsol Sinopec Resources-operated Flotta terminal in the Orkney Islands, Scotland.[8]

Forties blend is made up of oil from more than 50 fields spread over a large area of the North Sea, the biggest of which is the Buzzard oil field. Forties blend is a light (about 39° API) sweet (about 0.7% sulfur) crude oil, but the overall quality can vary based on Buzzard field volumes, which are heavier (32.6° API) and more sour (1.44% sulfur) than the rest of the blend volumes. The Forties system occupies most of the Central North Sea, located south of the Brent complex and east of Flotta. Once produced, Forties blend is shipped via the 105-mile pipeline to Cruden Bay, Scotland, where it is pumped another 130 miles to Hound Point, at the Forties' loading port, which is also in Scotland.[10]

Brent blend is a light (40.1° API), sweet crude (0.35% sulfur).[11] More than two dozen UK fields contribute to the blend, although very little production comes from the once-prolific Brent field, after which the stream was named. The Brent blend is transported to the Sullom Voe terminal via pipelines. This terminal, located in Scotland's Shetland Islands, is operated by Enquest, which acquired a 3% stake and the operatorship of the terminal from BP in 2017.[12] Despite the declining physical volumes associated with the Brent blend, its importance as a financial benchmark is increasing.

Brent benchmark crude

A benchmark crude is a specific crude oil that is widely and actively bought and sold, and to which other types of crude oil can be compared to determine a price by an agreed-upon differential. The Brent benchmark, the most widely-used global crude oil benchmark, is composed of five crude oil blends: Brent, Forties, Ekofisk, Oseberg (BFOE), and Troll, which was added January 1, 2018. The Brent and Forties blends are produced offshore in the waters of the UK, and the Ekofisk, Oseberg, and Troll blends are mainly produced offshore in the waters of Norway.

The Brent benchmark was originally based on the output of the Brent field, a single field in the UK's sector of the North Sea. At its peak in 1984, the Brent field alone produced more than 400,000 b/d from four platforms. During the late 1980s, production declined rapidly, and after a brief resurgence in the early 1990s, the declines resumed. In 2014, production ceased from two of the three remaining, operating platforms in the Brent field. Production from the single remaining platform in 2016 averaged less than 1,000 b/d and is likely to be shut down in the near future, leaving the Brent blend to continue on with no Brent crude oil.

As production from the Brent field declined, other fields and blends were added. Although the benchmark itself accounts for only a small portion of total world crude oil production, it remains a key indicator for world crude oil pricing.

UK's oil fields and operators

In 2016, Nexen was the largest oil field operator in the UK in terms of oil production. Nexen is a wholly owned subsidiary of the China National Offshore Oil Corporation (CNOOC). In 2016, Nexen operated nine fields in the UK, which produced a total of about 235,000 b/d in 2016. Nexen-operated fields accounted for 24% of total UK production in 2016.

The UK's largest producing field in 2016 was the Nexen-operated Buzzard oil field, which produced an average of 150,000 b/d during the year (Table 1).[13] Buzzard field came online in 2007, and production peaked at slightly less than 200,000 b/d in 2008.

Table 1. The United Kingdom's top 10 producing oil fields, 2016
FieldThousand barrels
per day
Golden Eagle57
Total top 10 fields432
Total UK978
Source: U.S. Energy Information Administration based on UK Energy Portal Petroleum Production Reporting System
Consumption and imports

In 2016, the UK consumed 1.6 million b/d of petroleum and other liquids. The transportation and industrial sectors accounted for more than 90% of petroleum consumption (Figure 4).[14]

Demand for middle distillates, in particular diesel, has steadily increased in the UK. Distillate fuel oil accounted for 36% of UK consumption, and motor gasoline and kerosene jet fuel each accounted for 17% in 2016.[15] Demand for motor gasoline has fallen gradually since 1990 as more drivers switch to diesel vehicles and as vehicle efficiency increases.

The United Kingdom's domestic refining sector is a significant crude oil importer, receiving 0.9 million b/d in 2016. Norway supplied 64% of the UK's imports of crude oil in 2016. African countries, particularly Nigeria and Algeria, supplied 21% of crude oil imports. Other Europe and Eurasia supplied 7%, with most of that coming from Russia. The Americas and the Middle East supplied 5% and 3%, respectively (Figure 5).[16]

Figure 5. United Kingdom  crude oil and condensate imports by origin, 2016

Figure 4. United Kingdom petroleum demand by sector, 2014


Despite the large declines in oil production over the past few years, the UK is still one of the largest petroleum producers and exporters in Europe. The country exported about 600,000 b/d of crude oil in 2016.

Once a major exporter of oil, UK exports have dropped along with decreasing domestic production. UK crude oil exports peaked in 2000 at 1.8 million b/d, declining to 0.6 million b/d in 2016.[17] However, despite being a net importer of crude oil and petroleum products, the UK is still one of the largest petroleum producers and exporters in Europe.

Most of the country's crude oil exports (72%) went to EU countries, mainly the Netherlands and Germany. The bulk of the exports to Germany are for refining and consumption there, while exports to the Netherlands include oil ultimately destined for other countries. Most of the non-EU export trade was with China (14%) and South Korea (8%) (Figure 6).[18]

Figure 6. United Kingdom crude oil and condensate exports by destination, 2014


The UK has an extensive network of pipelines that carry oil extracted from North Sea platforms to coastal terminals in Scotland and in northern England. The network includes six major pipelines (Table 2).[19] Many smaller pipelines transport petroleum liquids from individual fields to the major pipelines for transport to shore. Pipelines in the UK are privately owned and operated; however, any qualified shipper can access the pipelines.

Table 2. United Kingdom's major crude and condensate pipelines
FacilityStatusCapacity (million b/d)Total length (miles)OriginDestinationDetails
Norpipeoperating0.8220Ekofisk area fields (Norway) with a spur to UK fieldsTeesside, England oil terminal and refinerystarted operations in 1975; operated by ConocoPhillips
Piper-Flottaoperating0.4130Piper, Claymore, Golden Eagle and other nearby fieldsFlotta oil terminal, Orkney Islands, Scotlandstarted operations in 1976; operated by Repsol Sinopec Resources
Brent Pipeline System (BPS)operating0.195Cormorant-A platformSullom Voe terminalstarted operations in 1978; operated by TAQA
Ninian Pipeline Systemoperating0.9109Ninian area fieldsSullom Voe terminalstarted operations in 1978; operated by EnQuest which acquired a stake in the pipeline and operatorship of it from BP in 2017
Forties Pipeline System (FPS)operating0.6235Forties area fieldsHound Point crude export terminal and Grangemouth refinery and petrochemical complexstarted operations in 1975; operated by Ineos which acquired the pipeline from BP in 2017
Bruce-Fortiesoperating0.3154Bruce area fieldsForties Pipeline Systemstarted operations in 1993; operated by BP
Sources: U. S. Energy Information Administration based on ConocoPhillips, Repsol Sinopec Resources, TAQA, Enquest, Ineos, and BP
Refining sector

The UK had 1.4 million b/d of refining capacity at the end of 2017, according to OGJ.[20] Refinery output decreased by 2% from 2015 to 2016.[21]

After a long period as a net exporter of petroleum products, the UK became a net importer of petroleum products in 2013, with total net product imports growing to 215,000 b/d in 2016. UK refineries produce more gasoline and fuel oil than is used domestically, so the UK remains a net exporter of these products. However, because UK refineries cannot meet local demand for many other fuels, including diesel, imports continue to grow. Net diesel imports in 2016 were 242,000 b/d, up about 10% from the 2015 level. In 2016, net imports of diesel accounted for 48% of total UK diesel demand.[22] The largest source of imported diesel was the United States, accounting for 24% of total diesel imports in 2016. Russia accounted for 21% of UK diesel imports, and the Netherlands accounted for 19%.[23]

Hydrocarbon gas liquids

UK production of hydrocarbon gas liquids (HGL) has been generally declining, reflecting the downward trend in UK natural gas production and refinery output. HGL refers to both the natural gas liquids (paraffins or alkanes such as ethane, propane, and butanes) and to olefins (alkenes) produced by natural gas processing plants, fractionators, crude oil refineries, and condensate splitters but excludes liquefied natural gas and aromatics. HGL are produced in association with both natural gas and petroleum products.

As a result of falling natural gas production in the North Sea, UK domestic ethane production declined from a peak of 93,000 b/d in 1999 down to 16,000 b/d in 2015 (Figure 7).[24] UK petrochemical producers which require ethane as a feedstock, began importing ethane from Norway in 2007, but supplies proved insufficient. One petrochemical plant, the INEOS Train 2 ethylene cracker at Grangemouth, was shut.[25] More recent imports from the United States, starting in September 2016, have allowed both a restart of the INEOS Train 2 plant as well as the increase or re-introduction of ethane as feedstock to other ethylene crackers in the UK, including the ExxonMobil/Shell plant at Mossmorran and the SABIC plant at Wilton.[26]

Figure 7. Figure 7. United Kingdom ethane supply

Natural gas

The UK's natural gas production and consumption have been on a long-term declining trend; however, since 2014, both have been flat or have increased.

UK natural gas production peaked in 2000, and consumption peaked in 2004 with both generally declining through 2014 (figure 8). From 2014 through 2016, production has grown at an average rate of 5% per year, while consumption has grown 7% per year.

Figure 8. United Kingdom dry natural gas production and consumption

Sector organization

The UK natural gas sector is fully privatized, including production, transmission, and distribution. The largest natural gas distributor in the UK is Centrica, a spin-off of the distribution assets of formally state-owned British Gas. Centrica had a 35% market share in the UK natural gas market at the end of 2016, according to the UK Office of Gas and Electricity Markets (Ofgem). There are five other large suppliers (SSE, E. On, Scottish Power, RWE nPower, and EDF) that each had a market share of between 8% and 12%.[27]

The UK natural gas distribution sector underwent a major change in 2005, when National Grid Gas sold four of the eight gas distribution networks to Scotia Gas Networks, Wales and West Utilities, and Northern Gas Networks. Prior to this sale, National Grid controlled the domestic natural gas distribution system.

Exploration and production

According to the OGJ, the UK held an estimated 6.2 trillion cubic feet (Tcf) of proved natural gas reserves as of January 2018.[28] Indigenous UK natural gas production accounted for 47% of total natural gas supply in 2016 (Figure 9).[29]

Most of the UK's natural gas production comes from offshore liquids fields, accounting for 66% of total gross natural gas production in 2016. Natural gas production from these associated fields increased by 14% from 2015 to 2016. Natural gas from offshore dry gas fields accounted for slightly more than 33% of production in 2016, and onshore fields accounted for less than 1% of total gross natural gas production.[30]

UK natural gas production peaked in 2000 at 3.8 Tcf. From 2000 to 2014, production declined at an average rate of 7% per year. High oil and natural gas prices before and during 2014 helped spur high levels of investment in North Sea assets over the past several years. Investments made during the past few years have resulted in production increases since 2014. From 2014 to 2016, production increased at an average rate of 5% per year (Figure 8).


Estimates of natural gas and liquids resources in shale formations in the UK vary considerably. Shale testing is still at an early phase in the UK, and, compared with North America, the shale geology of the UK is considerably more complex. The two formations that have received the most attention so far are the Bowland shales, which are present throughout parts of northwest, central, and eastern England, and the Weald basin in southern England. The Bowland shales are more likely to hold natural gas, and the Weald is more likely to hold liquid hydrocarbons.

In 2011, hydraulic fracturing at a shale well in the Bowland basin triggered two minor earthquakes. After this incident, the UK government imposed a moratorium on hydraulic fracturing. In December 2012, the government imposed additional requirements for monitoring and controls and then allowed shale drilling and fracturing to resume. Companies must receive permission from the UK government as well as from local council governments before they can drill or fracture any new wells. Although the UK government is generally supportive of shale exploration and development activities, companies have faced opposition from local councils or environmental groups, with the first new shale well since the moratorium not drilled until 2017.

The Scottish energy minister announced a ban on hydraulic fracturing in Scotland in 2015, and in 2017, the Scottish parliament also voted for a ban, further strengthening the ban and extending it indefinitely.

Figure 9. United Kingdom natural gas supply mix, 2016

Consumption, imports, and exports

Natural gas consumption in the UK was slightly less than 2.9 Tcf in 2016, a 13% increase from the level in 2015. Residential natural gas consumption, much of which is for home heating, accounted for 35% of total consumption in 2016 (Figure 10).[31] Natural gas consumption in the public electricity sector increased by more than 45% from 2015 to 2016. This large increase in natural gas use is mainly because of declining coal use in the electric sector. From 2015 to 2016, coal-fired electric capacity declined by 23%,[32] and generation from coal declined by 60%.[33]

In 2004, the UK became a net importer of natural gas. The UK imported 1.7 Tcf of natural gas in 2016, with 77% coming by pipeline and the rest imported as liquefied natural gas (LNG). Imports from Norway and Qatar combined accounted for 87% of total imports. The UK also exports natural gas to the European continent and to the Republic of Ireland via pipeline. In 2016, UK natural gas exports totaled 0.4 Tcf.[34]

Liquefied natural gas (LNG)

The UK received the world's first trans-oceanic delivery of LNG in January 1959 and the world's first commercial LNG cargo in October 1964. The UK continued importing LNG until the early 1980s when growing North Sea natural gas production supplanted imports. However, in the early 2000s, growing natural gas demand and falling North Sea production led to the construction of new LNG import terminals and the resumption of LNG imports in 2005. Currently, the UK has three operating LNG import terminals with total import capacity of 1.7 Tcf per year. Over the past several years, average utilization rates of these terminals have been low. However, LNG imports can vary considerably from month to month and from year to year in response to changing UK, European, and global market conditions. In early 2011, terminal utilization rates were at more than 50%, before the Fukushima disaster increased demand for LNG in Japan, leading to a tighter global LNG market. By the end of 2011, utilization rates at UK LNG terminals fell to about 30% as more LNG cargoes were directed to Asia.

In 2016, the UK imported 388 billion cubic feet (Bcf) of LNG, down 21% from 2015.[35] Qatar is by far the largest source of LNG imported into the UK, accounting for more than 90% of LNG imports each year since 2012.[36]

In March 2013, Centrica signed a 20-year contract with Cheniere Energy to buy LNG from train 5 of the Sabine Pass LNG facility in Louisiana. Construction of train 5 started in June 2015, and it is scheduled to be online by the end of 2019. Centrica is contracted to buy about 1.75 million metric tons of LNG (89 Bcf of natural gas) from Cheniere per year and has import capacity rights at the UK's Isle of Grain LNG terminal.[37]

Figure 8. United Kingdom natural gas demand by sector, 2014


Several pipeline systems carry natural gas from UK and Norwegian offshore platforms to coastal landing terminals (Table 3).[38] The UK also has two natural gas pipeline interconnections with the Republic of Ireland, an undersea link from Scotland, and a smaller-capacity link from Northern Ireland. The UK also has two pipeline connections with continental Europe, including the Interconnector pipeline, which is bi-directional.

Table 3. United Kingdom's major natural gas pipelines
FacilityStatusCapacity (trillion cubic feet per year)Total length (miles)OriginDestinationDetails
Frigg Pipeline System (FUKA)operating0.5225UK and Norwegian North SeaSt. Fergus, Scotlandstarted operation in 1977
Vesterledoperating0.5224Norwegian North SeaSt. Fergus, Scotlandstarted operation in 1978 as the Frigg Norwegian Pipeline; was extended and renamed Vesterled in 2001
Far north Liquids and Associated Gas System (FLAGS)operating0.4280UK and Norwegian North SeaSt. Fergus, Scotlandstarted operation in 1982
Scottish Area Gas Evacuation (SAGE)operating0.4201UK and Norwegian North SeaSt. Fergus, Scotlandstarted operation in 1992
Central Area Transmission System (CATS)operating0.6251UK North SeaTeesside, Englandstarted operation in 1993
UK-Eire Interconnectoroperating0.4120Moffat, Scotland Republic of Irelandstarted operation in 1993
Interconnector UKoperatingbi-directional146  originally designed to mainly flow gas from the UK to the European continent; started operation in 1998
  0.7 Bacton, UKZeebrugge, Belgiumforward flow direction
  0.9 Zeebrugge, BelgiumBacton, Englandreverse flow direction; original capacity was 0.3 Tcf
Shearwater Elgin Area Line (SEAL)operating0.5295UK North SeaBacton, Englandstarted operation in 2000
Balgzand-Bacton line (BBL)operating0.6146Balgzand, NetherlandsBacton, Englandstarted operation in 2006
Tampen and Gjøaoperating0.614 (Tampen) and 81 (Gjøa)Norwegian North SeaFLAGS pipelinestarted operation in 2007 (Tampen) and 2010 (Gjøa)
Langeled pipelineoperating1.0725Nyhamna gas plant, NorwayEasington, Englandstarted operation in 2007
Shetland Island Regional Gas Export System (SIRGE)operating0.7145Shetland gas plant at Sullom VoeFUKA pipelinestarted operation in 2016
Sources: U. S. Energy Information Administration based on North Sea Midstream Partners, Gassco, Shell, Apache Corp, CATS management Limited, Interconnector (UK), BG, BBL Company, and Digest of UK Energy Statistics.

Coal production in the UK is declining as a result of environmental regulations and falling consumption.

Coal production in the UK has generally been declining since the early 1900s, falling from 322 million short tons (MMst) in 1913 (the first year for which annual data are available) to a record low of 5 MMst in 2016 (Figure 11).

Coal consumption in the UK peaked at 244 MMst in 1956, the year in which the UK enacted the Clean Air Act. The Clean Air Act—prompted by the great London smog of 1952—prohibited the emission of dark smoke from industrial buildings, private homes, and railroad locomotives. At the time, industrial coal use accounted for more than half of total UK coal consumption, and railroad and home use accounted for almost a quarter of total coal consumption. The remaining coal consumption was mainly in the electric sector where coal consumption did not peak until the 1980s at slightly less than 100 MMst. Coal consumption in 2016 was 20 MMst, two-thirds of which was used in the electric sector.[39]

Environmental regulations, competing fuels, and competing foreign coal supply sources have been the main drivers of coal's long decline in the UK. Natural gas began replacing coal in the 1970s when natural gas production began in the North Sea. In the 1990s, coal's displacement by natural gas accelerated as regulatory changes opened the electric sector to more investment in natural gas-fired generation capacity. Coal consumption experienced a brief resurgence in 2012, growing 14 MMst from 2011 levels. This resurgence in demand did not extend to UK coal production but was instead accompanied by an uptick in imports. The availability of cheap coal from the United States was one of the main drivers in the growth of coal consumption, along with relatively high natural gas prices and low carbon prices. Coal consumption resumed its decline in 2013, falling an average of more than 25% per year from 2012 through 2016, as natural gas prices declined and as the UK's Carbon Price Floor policy increased the cost of carbon emissions.

The UK had an estimated 77 MMst of recoverable coal reserves at the end of 2016, according to BP's Statistical Review of World Energy 2017.[40] Deep coal mines had been operating in the UK since the 1800s, however the last deep coal mine in the UK closed in December 2015. Several surface mines remain in operation in the UK and are mainly located in central and northern England, south Wales, and central and southern Scotland.

Figure 11. United Kingdom coal production, imports, and consumption


Slightly more than half of the electricity generated in the UK in 2016 came from fossil fuels. However, electricity generated from renewable sources, especially wind, continues to grow.

In 2016, a little more than half of electricity generation in the UK came from fossil fuels (Figure 12),[41] particularly natural gas (46%).The UK had 98 gigawatts (GW) of installed electricity generation capacity at the end of 2016.[42] Nonrenewables capacity has fallen since 2010 as several fossil fuel-fired plants and a few nuclear reactors have shut down. In 2016, net UK electric generation was 324 billion kilowatthours (kWh) of electricity, while consumption was 342 billion kWh, down 14% and 12%, respectively, from 2006 levels.[43]

Figure 12. United Kingdom electricity generation by fuel source, 2014

Sector organization

The UK has a privatized electricity sector, where electric generators and marketers operate in a competitive environment. EDF Energy, a subsidiary of Électricité de France, was the largest supplier of electricity to the national transmission system in 2016, accounting for 24% of generation. The retail electric market is dominated by six large providers, with British Gas accounting for about one-quarter of the total market. The share of independent providers in the retail market is growing, accounting for about 15% of the market at the end of 2016, up from 1% at the beginning of 2012.[44]

The UK electric transmission system is regulated and is managed by independent system operators. The electric transmission systems of England, Wales, and Scotland are fully integrated and are operated as a single market by National Grid Electricity Transmission plc (National Grid), which also owns the electric transmission system in England and Wales. The electricity grid in Northern Ireland is integrated with the grid of the Republic of Ireland, and the combined system is operated by the Single Electricity Market Operator (SEMO). The UK transmission system has two interconnections with the Irish system—one between Scotland and Northern Ireland and one between Wales and the Republic of Ireland. The UK system also has two interconnections with continental Europe—one each with France and the Netherlands.[45]

The UK government's energy policies have long sought to encourage the use of low-carbon sources of energy to generate electricity. The UK's Non Fossil Fuel Obligation (NFFO) was introduced in 1990 to support nuclear and renewables generation. In 2002, the UK replaced the NFFO with the Renewables Obligation (RO), which continued support for renewables generation but did not include support for nuclear generation. The government is phasing out the RO support system, and beginning in 2017, the main method of renewables support will be via feed-in tariffs (FIT) implemented as contracts for difference (CfD). A FIT offers a guaranteed price for electricity generated by qualifying generation projects. FITs can be implemented in several ways (see Feed in Tariff). Under the UK support system, once the government establishes a FIT—also called a strike price—for a project, the government and the project developer sign a long-term CfD contract. Under the CfD, when the market price for electricity is lower than the FIT price, the government pays the generation company the difference. If the market price is higher than the FIT price, the generation company must pay the government the difference. Projects that can qualify for support under this new system include renewables generation facilities as well as projects to build nuclear power plants and carbon capture and storage facilities.

Another government program that supports the use of renewables and other low carbon sources of electricity generation is the UK's Carbon Price Floor (CPF), established in April 2013 for the 2013–14 tax year. The UK's CPF works in combination with the EU's Emissions Trading System (ETS). If the EU ETS carbon price is lower than the UK CPF, electric generators have to buy credits from the UK Treasury to make up the difference. The CPF applies to both generators that produce electricity for the grid and companies that produce electricity for their own use. Since the beginning of 2012, the EU ETS carbon price has stayed below 10 Euro per metric ton of carbon (below GBP 8 per metric ton or below US$13 per metric ton). The UK CPF has gradually risen to GBP 18 per ton of carbon (about US$25 per ton), where it will remain at least through the 2019-20 fiscal year. The CPF was originally designed to rise to GBP 30 per ton of carbon in 2020 and GBP 70 per ton of carbon in 2030 (about US$40 and US$95 per ton, respectively), but was it capped to limit the impact on businesses.[46]

Fossil fuel generation

The share of electricity from the burning of fossil fuels is declining as renewables generation increases.

For most of the past 20 years, fossil fuels have accounted for about 70% to 80% of total electric generation, and they continue to provide most of the electricity supply in the UK. In 2008, fossil fuel-fired generation peaked at 81% of total electricity supply and has since declined to 56% in 2016. At the same time, renewables generation has grown from 5% of total generation to almost 20% of total generation.

Natural gas-fired generation provides most of the UK's electricity, accounting for 46% of total generation in 2016. Coal and natural gas have long competed for share of the electric generation market. The relative price of the two fuels and the costs for complying with environmental regulations at any given time have been the major factors influencing the relative market shares of each fuel.

From 2009 to 2012, U.S. coal exports more than doubled, helping to push down global coal prices. Over the same period, UK natural gas prices nearly doubled, and carbon prices halved. Consequently, the share of coal-fired generation in total electricity generation increased by 12%, while the share of natural gas declined by 17%. Since 2012, coal-fired generation has lost market share as the CPF has increased the costs of carbon emissions and as several coal-fired power plants have been shut down or converted to burn biomass which is not subject to the CPF. Oil-fired power plants continue to provide minor amounts of electricity, accounting for less than 1% of total generation in 2016.


Currently accounting for one-fifth of total electricity generation, nuclear power plants are central to the UK government plans for future electricity generation.

At the end of 2017, the UK had 15 operating nuclear reactors, with a current capacity of slightly less than 9 gigawatt electric (GWe), according to the World Nuclear Association. All 15 operating reactors are owned and operated by EDF Energy. Most of the existing nuclear capacity started operations in the 1970s or 1980s and is due to be shut down by 2025.[47] Nuclear power generation accounted for 20% of the country's total gross generation in 2016.[48]

In the 1990s and early 2000s, the UK government viewed new nuclear capacity as unappealing because of its economic costs and the problem of disposing of nuclear waste.[49] Government policies began to shift toward support for new nuclear capacity, beginning in 2006, with the release of a government energy white paper declaring that nuclear generation could make a significant contribution to meeting the country's energy goals. Recent government policy statements project that the UK will need an additional 25 GWe of new nonrenewable generating capacity by 2030 and that a significant portion of this capacity should come from new nuclear facilities.

The Hinkley Point C project is expected to be the first new nuclear facility to come online in the UK since 1995. The Hinkley Point C project is being led by EDF Energy with China General Nuclear Power Corporation (CGN) taking a minority stake in the project. The project includes building two new reactors at the existing Hinkley Point nuclear site. The two reactors will have a combined capacity of 3.2 GWe. The target start date for the first reactor was originally 2017, but the schedule has slipped pushing the likely startup date to 2026. In October 2013, the UK government agreed a CfD with EDF Energy guaranteeing a price of GBP 92.50 per MWh (about US$140 per MWh) for power generated by the Hinkley Point C project. In 2015, wholesale power prices in the UK were less than GBP 50 per MWh (about US$75 per MWh).

A total of 13 new nuclear units are planned or proposed for the UK with a total capacity of almost 18 GWe of generating capacity.[50]

  • Data presented in the text are the most recent available as of March 19, 2018.
  • Data are EIA estimates unless otherwise noted.

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The World’s Largest Natural Gas Discovery Since 2005

At the start of February, a major new find was jointly announced by the two largest emirates within the UAE: the oil-rich Abu Dhabi and the ambitious Dubai. Between them, they literally made the world’s largest natural gas discovery since 2005. Located at the border between the two sheikdoms, the Jebel Ali field is estimated to contain some 80 trillion scf of natural gas, the largest global find since the Galkynysh field in Turkmenistan.

Stretching over 5,000 square km, an exploration campaign by Abu Dhabi involving over 10 wells confirmed the enormous discovery in early January 2020. The shallow nature of the onshore reserves should make it easier to extract gas at lower costs, hastening the time-to-market. At current estimated figures, Jebel Ali would be the fourth-largest gas field in the Middle East, behind Qatar’s North Field, Iran’s South Pars and Abu Dhabi’s own Bab field.

The politics of the UAE can be complicated; each emirate is essentially self-governing with federal oversight, which is dominated by Abu Dhabi and Dubai (which always hold the President and Prime Minister roles, according to convention). This essentially means that each emirate has grew quite independently. Fujairah, for example, developed into a bunkering port, while Sharjah went into industry and manufacturing. Dubai is globally famous for its titanic real estate projects, pursued finance, services and media, while Abu Dhabi, the largest and most blessed of all with hydrocarbon resources, turned into an energy powerhouse. Oil & gas wealth in the UAE is mainly in Abu Dhabi; so while the Jebel Ali discovery is a welcome addition for Abu Dhabi, it is a game changer for Dubai, which imports most of its energy needs.

Speculation has raised that possibility that the Jebel Ali field could vault the UAE into gas self-sufficiency, because even Abu Dhabi imports gas. The UAE has a stated goal to be gas independent by 2030. On paper, that’s possible. Abu Dhabi’s ADNOC has agreed to develop the field with Dubai’s gas supplier, the Dubai Supply Authority (DUSUP), with the entire supply will be channel to DUSUP for use in Dubai. Jebel Ali could begin producing gas by 2023, and will likely be distributed domestically through pipeline. The enormous reserves could supply the entire UAE’s gas demand for nearly 30 years, assuming optimal recovery conditions. However, in practice, self-sufficiency might take longer to achieve.

Dubai and indeed, Abu Dhabi are currently reliant on Qatar for their gas supply. An existing sales agreement that expires in 2032 sees Qatar pipe 2 bcf/d of gas to the UAE through Abu Dhabi. The problem is that these neighbours are erstwhile friends. A division in the Middle East between the pro-Saudi Arabia and pro-Iran blocs has caused a rift. Led by Saudi Arabia, several Persian Gulf states  including the UAE implemented a diplomatic and trade blockade on Qatar, isolating it. The blockade, slightly weakened, still continues today. Even now, planes flying into Qatar have to make strange manoeuvres when approaching to avoid encroaching on Saudi and UAE airspace. However, the gas supply arrangement remains in place.

And this is where the Jebel Ali discovery could come in handy. Qatar is already on track to be self-sufficient in gas terms by 2025, but will probably honour the Qatar deal until expiration. Dubai has been increasingly reliant on LNG  through an FSRU for power generation, but has attempted over the years to kick-start a number of coal or solar-power projects. Jebel Ali won’t kick the addiction, but it could definitely reduce Dubai’s reliance on Qatari gas.

Jebel Ali wasn’t the only recent gas discovery made in the UAE. Further north, the Sharjah National Oil Corp and Italy’s Eni announced a new onshore gas and condensate discovery. Though tiny in comparison to Jebel Ali, some 50 mscf/d of lean gas and condensate. The cumulative effects of these discoveries could make gas self-sufficiency a reality sooner. At this point, the UAE consumes some 7.4 bcf gas per day, while marketed production is some 6.2 bcf/d. An ambitious plan to develop Abu Dhabi’s large gas fields was the rationale behind naming the 2030 self-sufficiency deadline. With the discovery of Jebel Ali, that can now be brought forward by a couple of years at least. And there might even be some left over to be exported as LNG

The UAE Major Gas Projects:

  • Estimated reserves: 273 tcf of conventional gas, 160 tcf of unconventional gas (Abu Dhabi)
  • Ghasha ultra-sour gas field (Abu Dhabi) – 1.5 bcf, by 2025
  • Shah sour gas field (Abu Dhabi) – 1.5 bcf/d

February, 23 2020
Your Weekly Update: 17 - 21 February 2020

Market Watch   

Headline crude prices for the week beginning 17 February 2020 – Brent: US$53/b; WTI: US$49/b

  • As the Covid-19 pandemic seems to be coming increasingly under control, crude oil prices are recovering some ground as the market moves into speculative mode given the availability of cheap crude cargoes
  • Case in point, while the fear was of widespread demand destruction in China, a sudden buying spree by Chinese independent teapot refineries – attracted by cheap spot cargoes – surprised the market, being a sign that Chinese private refiners are anticipating a rebound in demand sooner rather than later
  • Despite this, the pandemic is still recalibrating Chinese energy demand in a dramatic way, with reports of four LNG tanker bound for northern China from Oman and Qatar diverted as CNOOC invoked force majeure on its contracts
  • China’s pain is also India’s gain, with so-called ‘distressed cargoes’ originally intended for China now offered to India at attractive terms from all over the world, including grades from the Caspian Sea to Latin America and West Africa
  • Based on the situation in China, the IEA is forecasting the first annual decline in quarterly global oil demand for the first time in over a decade, and dragging overall 2020 growth down by 30% to 825,000 b/d; the EIA followed suit as well, cutting its Brent price forecast for 2020 from US$64.83 to US$61.25
  • China and key Asian hubs impacted by the virus like Hong Kong and Singapore have pledged to provide extra fiscal stimulus to counteract the impact of the pandemic, possibly setting the stage for a rebound in Q2 2020
  • Saudi Arabia’s attempt to cajole the OPEC+ club into extending its supply cuts until June 2020 through an emergency February meeting has faded, with Russia being the main holdout
  • Amid the turmoil in the markets, the US active rig count remained unchanged for the week, adding two oil sites but losing gas and miscellaneous sites for a total of 790
  • Oil prices gained over the week as the Covid-19 pandemic looks to be contained; Brent should trade in a higher US$57-59/b range and WTI at US$43-55/b

Headlines of the week


  • Saudi Arabia and Kuwait have officially restarted production from their shared Wafra field in the Neutral after five years of halted output
  • Despite being hampered by quarterly waivers that are subject to renewals by the US government, Chevron has ramped up production at its Petropiar crude upgrader plant in Venezuela to 130,000 b/d after being closed for most of 2019
  • Canada’s Alberta province’s plan to ease its crude glut through rail shipments has hit a snag, as protestors blocked train lines and the provincial government ordered trains to reduce speeds after a major derailment and fire
  • Tullow Oil reports that it has received approval from Ghana to flare gas ‘when necessary’ from its offshore fields, which should help the beleaguered company support production levels after a set of disappointing results for 2019
  • Somalia has passed a new petroleum bill into law, with the aim of setting up a regulatory framework to attract foreign upstream investment; Somalia currently does not produce any oil but estimates suggest significant reserves
  • As Uganda prepares to start producing oil for the first time, distribution and transport infrastructure remain an issue, with the state recently tapping a Chinese lender to build three roads to connect to its western oilfields
  • After a challenging few years of scandals and a subsequent refocusing on upstream, Petrobras has now hit a new upstream production record, with the ramp-up in pre-salt basins contributing to 3.025 mmboe/d in Q4 2019
  • CNOOC has commenced production at the offshore Bozhong 34-9 field in the Bohai Sea, with peak output expected at 22,500 b/d of crude by 2022


  • The Covid-19 Wuhan outbreak has claimed a few more refinery scalps, with ChemChina shutting down its 100 kb/d Zhenghe refinery in Shandong and reducing processing at its Changyi and Huaxing refineries by 10%; Hengli Petrochemical has cut utilisation rates at its new 400 kb/d Dalian refinery by some 17% as well, as petchem demand dries up
  • The 120,000 b/d Azzawiya Oil Refining Company refinery in Libya has been forced to halt all operations, as a prolonged conflict in the country has dried up the availability of crude for export or local refining
  • Egypt has given the go-ahead for a US$2.5 billion, 65 kb/d oil refinery in the Upper Egypt region, focusing on hydrocracking mazut – heavy, low quality fuel oil typically used for power generation – into high-value fuels
  • The Bangladesh Petroleum Corp has awarded a tender to supply some 1.06 million tons of gasoil, jet fuel, fuel oil and gasoline to Unipec and Vitol
  • Vietnam’s Nghi Son refining has offered a cargo of gasoil for export for the first time – an indication of slowing domestic demand from the Covid-19 outbreak that is hitting most major East and Southeast Asian economies

Natural Gas/LNG

  • NextDecade Corp’s US$15 billion, 26 million tons per annum Rio Grande LNG facility in Texas has been cleared for LNG exports by the US DoE
  • Portugal’s Sines port is being eyed by US energy companies as a strategic landing point for US LNG exports to Europe, as American LNG exporters race to lock down customers amid a supply glut that could last for years
  • Shell has acquired a 50% stake in Ecopetrol’s Fuerte Sur, Purple Angel and COL-5 gas blocks located in Colombia’s Caribbean deepwater region
February, 21 2020
This Week in Petroleum

Forecast growth in demand for U.S. petroleum and other liquids is not driven by transportation and not supplied by refineries

The U.S. Energy Information Administration’s (EIA) February Short-Term Energy Outlook (STEO) forecasts that in 2021, U.S. consumption (as measured by product supplied) of total petroleum and other liquid fuels will average 20.71 million barrels per day (b/d), surpassing the 2007 pre-recession level of 20.68 million b/d. However, the drivers of this consumption growth have changed. Since the 2007–09 recession, U.S. consumption growth has shifted toward liquid fuels that are used primarily outside the transportation sector and are supplied mostly from non-refinery sources. Despite this shift away from domestic demand for refinery-produced fuels, U.S. refinery runs have increased, and the excess products have been exported, greatly contributing to the United States becoming a net exporter of petroleum in September 2019. EIA expects these trends to continue for at least the next 10 years.

Hydrocarbon gas liquids (HGL) have been the main driver of U.S. petroleum and other liquids demand growth since 2007 (Figure 1). U.S. production and consumption of HGLs—a group of products that include ethane, propane, normal butane and isobutane, natural gasoline, and refinery olefins—have risen with increased natural gas production and demand from an expanding petrochemical sector. As a result, EIA forecasts U.S. HGL consumption will be 1.27 million b/d more in 2021 than in 2007, and will average 3.45 million b/d.

Figure 1. Forecast change in U.S. consumption from 2007 to 2021

With the exception of jet fuel, EIA expects less U.S. consumption of refinery-produced products in 2021 than in 2007. Since 2007, increases in U.S. vehicle miles traveled, which normally increases total motor gasoline consumption, have been countered to some extent by increases in vehicle fuel efficiency. In addition, although U.S. total motor gasoline consumption exceeded 2007 levels for the first time in 2016, increased blending of ethanol into finished motor gasoline has displaced some of the petroleum-based, or refinery-produced, portion of gasoline consumption. Therefore, EIA forecasts 570,000 b/d less consumption of refinery-produced gasoline in the United States in 2021 than in 2007, while ethanol will be 0.5 million b/d higher. Ethanol is almost exclusively produced at non-petroleum refinery sites.

Some HGLs can be produced by both refineries and natural gas processing plants. Natural gas plant liquids (NGPLs)—a subset of HGLs that includes ethane, propane, normal butanes and isobutanes, and natural gasoline—can be extracted from natural gas production streams or produced at refineries that process crude oil. However, as U.S. natural gas production increased from 55.3 billion cubic feet per day (Bcf/d) in 2007 to 98.9 Bcf/d in 2019, the amount of HGLs extracted from natural gas production increased from 1.78 million b/d in 2007 to 4.83 million b/d in 2019. EIA expects HGL production from natural gas processing plants to continue to increase to 5.47 million b/d in 2021. Meanwhile, refinery HGL production has been flat at about 600,000 b/d (Figure 2).

Figure 2. U.S. hydrocarbon gas liquids production by source

Although HGLs have several different end uses, such as propane for space heating and normal butane for blending with motor gasoline, most of the growth in consumption stems from the use of HGLs as feedstock for petrochemical processes. The large increase in U.S. production of HGLs, and the resulting low prices, led to large investments in U.S. infrastructure to extract and transport HGLs to market, as well as investments in petrochemical facilities to consume it. Many of these facilities consume ethane, and to a lesser degree propane and normal butane, as feedstocks to produce intermediate building blocks for plastics, resins, and other materials with nonenergy uses. EIA forecasts that U.S. ethane consumption will reach 1.96 million b/d in 2021, up from 743,000 b/d in 2007, which represents 96% of the increase in U.S. HGL consumption between 2007 and 2021.

Removing HGL and ethanol consumption from the total demand for U.S. petroleum and other liquids indicates that EIA’s 2021 forecast U.S. demand for principally refinery-produced products is about 16.31 million b/d, on par with the 1997 level (Figure 3).

Figure 3. U.S. total petroleum and other liquids demand

Despite domestic demand shifting away from traditionally refinery-produced products, U.S. refinery capacity has increased 1.7 million b/d between 2007 and 2019. U.S. refineries have adapted to falling domestic demand for certain products, such as residual fuel, by investing in downstream coking capacity to upgrade it into more valuable products. More importantly, international demand for refinery-produced products has increased since 2007, allowing U.S. refineries to increase runs and utilization beyond what the domestic market demanded to supply products to export markets. As a result, the United States became a net exporter on an annual basis of distillate and residual fuel in 2008, of jet fuel in 2011, and of motor gasoline in 2016.

Similarly, demand for HGLs outside of the United States has increased and caused U.S exports of HGLs to increase from 70,000 b/d in 2007 to 2.07 million b/d in November 2019. Between 2013 and 2016, exports of HGLs were the largest contributor to the increase in U.S. exports of petroleum products. U.S. exports of HGLs are mostly of propane and ethane to markets in Asia and Europe, where they are also displacing refinery-produced naphtha as a petrochemical feedstock.

EIA projects that these trends of increasing U.S. production of HGLs, increasing domestic consumption of HGLs, and increasing exports of HGLs will continue beyond 2021. EIA’s Annual Energy Outlook 2020 (AEO2020), released in January, shows projections for further growth in HGL production at natural gas processing plants from 4.91 million b/d in 2019 to a peak of 6.58 million b/d in 2029 and then slowly decline to 6.17 million b/d by 2050. Domestic consumption of HGLs will also increase, driven by continued petrochemical demand for feedstock, which rises from about 3.14 million b/d in 2019 to more than 4.0 million b/d in 2029. Meanwhile, in the AEO2020 Reference case, U.S. consumption of motor gasoline declines until 2042, distillate consumption declines until 2040, and residual fuel consumption continues declining out to 2050.

U.S. average regular gasoline prices rise, diesel prices decline

The U.S. average regular gasoline retail price increased nearly 1 cent from the previous week to $2.43 per gallon on February 17, 11 cents higher than the same time last year. The Midwest price rose nearly 5 cents to $2.31 per gallon. The Rocky Mountain price fell more than 3 cents to $2.47 per gallon, the West Coast price fell 1 cent to $3.14 per gallon, the East Coast price fell nearly 1 cent to $2.36 per gallon, and the Gulf Coast price declined by less than 1 cent to $2.08 per gallon.

The U.S. average diesel fuel price fell 2 cents from the previous week to $2.89 per gallon on February 17, 12 cents lower than a year ago. The Rocky Mountain price fell nearly 4 cents to $2.86 per gallon, the East Coast price fell more than 2 cents to $2.94 per gallon, the Midwest and Gulf Coast prices each fell nearly 2 cents to $2.76 per gallon and $2.66 per gallon, respectively, and the West Coast price fell more than 1 cent to $3.47 per gallon.

Residential heating oil prices increase, propane prices decrease

As of February 17, 2020, residential heating oil prices averaged more than $2.91 per gallon, almost 1 cent per gallon above last week’s price but more than 31 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged $1.80 per gallon, more than 5 cents per gallon above last week’s price but 34 cents per gallon lower than a year ago.

Residential propane prices averaged more than $1.98 per gallon, less than 1 cent per gallon below last week’s price and nearly 45 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.56 per gallon, more than 1 cent per gallon higher than last week’s price but almost 27 cents per gallon below last year’s price.

Propane/propylene inventories decline

U.S. propane/propylene stocks decreased by 3.0 million barrels last week to 74.3 million barrels as of February 14, 2020, 18.4 million barrels (32.9%) greater than the five-year (2015-19) average inventory levels for this same time of year. Midwest, Gulf Coast, East Coast, and Rocky Mountain/West Coast inventories decreased by 1.1 million barrels, 1.0 million barrels, 0.6 million barrels, and 0.4 million barrels, respectively. Propylene non-fuel-use inventories represented 7.5% of total propane/propylene inventories.

February, 21 2020