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.
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). 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 1. Map of United Kingdom
Source: Central Intelligence Agency, The World FactbookPetroleum 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.
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). 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. 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. 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.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. 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. 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.
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.
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.
Brent blend is a light (40.1° API), sweet crude (0.35% sulfur). 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. 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). Buzzard field came online in 2007, and production peaked at slightly less than 200,000 b/d in 2008.
|Total top 10 fields||432|
|Source: U.S. Energy Information Administration based on UK Energy Portal Petroleum Production Reporting System|
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).
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. 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).
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. 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).
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). 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.
|Facility||Status||Capacity (million b/d)||Total length (miles)||Origin||Destination||Details|
|Norpipe||operating||0.8||220||Ekofisk area fields (Norway) with a spur to UK fields||Teesside, England oil terminal and refinery||started operations in 1975; operated by ConocoPhillips|
|Piper-Flotta||operating||0.4||130||Piper, Claymore, Golden Eagle and other nearby fields||Flotta oil terminal, Orkney Islands, Scotland||started operations in 1976; operated by Repsol Sinopec Resources|
|Brent Pipeline System (BPS)||operating||0.1||95||Cormorant-A platform||Sullom Voe terminal||started operations in 1978; operated by TAQA|
|Ninian Pipeline System||operating||0.9||109||Ninian area fields||Sullom Voe terminal||started 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)||operating||0.6||235||Forties area fields||Hound Point crude export terminal and Grangemouth refinery and petrochemical complex||started operations in 1975; operated by Ineos which acquired the pipeline from BP in 2017|
|Bruce-Forties||operating||0.3||154||Bruce area fields||Forties Pipeline System||started operations in 1993; operated by BP|
|Sources: U. S. Energy Information Administration based on ConocoPhillips, Repsol Sinopec Resources, TAQA, Enquest, Ineos, and BP|
The UK had 1.4 million b/d of refining capacity at the end of 2017, according to OGJ. Refinery output decreased by 2% from 2015 to 2016.
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. 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%.
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). 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. 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.
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.
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%.
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. Indigenous UK natural gas production accounted for 47% of total natural gas supply in 2016 (Figure 9).
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.
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.
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). 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%, and generation from coal declined by 60%.
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.
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. 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.
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.
Several pipeline systems carry natural gas from UK and Norwegian offshore platforms to coastal landing terminals (Table 3). 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.
|Facility||Status||Capacity (trillion cubic feet per year)||Total length (miles)||Origin||Destination||Details|
|Frigg Pipeline System (FUKA)||operating||0.5||225||UK and Norwegian North Sea||St. Fergus, Scotland||started operation in 1977|
|Vesterled||operating||0.5||224||Norwegian North Sea||St. Fergus, Scotland||started operation in 1978 as the Frigg Norwegian Pipeline; was extended and renamed Vesterled in 2001|
|Far north Liquids and Associated Gas System (FLAGS)||operating||0.4||280||UK and Norwegian North Sea||St. Fergus, Scotland||started operation in 1982|
|Scottish Area Gas Evacuation (SAGE)||operating||0.4||201||UK and Norwegian North Sea||St. Fergus, Scotland||started operation in 1992|
|Central Area Transmission System (CATS)||operating||0.6||251||UK North Sea||Teesside, England||started operation in 1993|
|UK-Eire Interconnector||operating||0.4||120||Moffat, ScotlandÂ||Republic of Ireland||started operation in 1993|
|Interconnector UK||operating||bi-directional||146||originally designed to mainly flow gas from the UK to the European continent; started operation in 1998|
|0.7||Bacton, UK||Zeebrugge, Belgium||forward flow direction|
|0.9||Zeebrugge, Belgium||Bacton, England||reverse flow direction; original capacity was 0.3 Tcf|
|Shearwater Elgin Area Line (SEAL)||operating||0.5||295||UK North Sea||Bacton, England||started operation in 2000|
|Balgzand-Bacton line (BBL)||operating||0.6||146||Balgzand, Netherlands||Bacton, England||started operation in 2006|
|Tampen and Gjøa||operating||0.6||14 (Tampen) and 81 (Gjøa)||Norwegian North Sea||FLAGS pipeline||started operation in 2007 (Tampen) and 2010 (Gjøa)|
|Langeled pipeline||operating||1.0||725||Nyhamna gas plant, Norway||Easington, England||started operation in 2007|
|Shetland Island Regional Gas Export System (SIRGE)||operating||0.7||145||Shetland gas plant at Sullom Voe||FUKA pipeline||started 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.
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. 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.
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), particularly natural gas (46%).The UK had 98 gigawatts (GW) of installed electricity generation capacity at the end of 2016. 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.
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.
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.
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.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.Nuclear
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. Nuclear power generation accounted for 20% of the country's total gross generation in 2016.
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. 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.Notes
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Throughout much of its history, the United States has imported more petroleum (which includes crude oil, refined petroleum products, and other liquids) than it has exported. That status changed in 2020. The U.S. Energy Information Administration’s (EIA) February 2021 Short-Term Energy Outlook (STEO) estimates that 2020 marked the first year that the United States exported more petroleum than it imported on an annual basis. However, largely because of declines in domestic crude oil production and corresponding increases in crude oil imports, EIA expects the United States to return to being a net petroleum importer on an annual basis in both 2021 and 2022.
EIA expects that increasing crude oil imports will drive the growth in net petroleum imports in 2021 and 2022 and more than offset changes in refined product net trade. EIA forecasts that net imports of crude oil will increase from its 2020 average of 2.7 million barrels per day (b/d) to 3.7 million b/d in 2021 and 4.4 million b/d in 2022.
Compared with crude oil trade, net exports of refined petroleum products did not change as much during 2020. On an annual average basis, U.S. net petroleum product exports—distillate fuel oil, hydrocarbon gas liquids, and motor gasoline, among others—averaged 3.2 million b/d in 2019 and 3.4 million b/d in 2020. EIA forecasts that net petroleum product exports will average 3.5 million b/d in 2021 and 3.9 million b/d in 2022 as global demand for petroleum products continues to increase from its recent low point in the first half of 2020.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), February 2021
EIA expects that the United States will import more crude oil to fill the widening gap between refinery inputs of crude oil and domestic crude oil production in 2021 and 2022. U.S. crude oil production declined by an estimated 0.9 million b/d (8%) to 11.3 million b/d in 2020 because of well curtailment and a drop in drilling activity related to low crude oil prices.
EIA expects the rising price of crude oil, which started in the fourth quarter of 2020, will contribute to more U.S. crude oil production later this year. EIA forecasts monthly domestic crude oil production will reach 11.3 million b/d by the end of 2021 and 11.9 million b/d by the end of 2022. These values are increases from the most recent monthly average of 11.1 million b/d in November 2020 (based on data in EIA’s Petroleum Supply Monthly) but still lower than the previous peak of 12.9 million b/d in November 2019.
In the past week, crude oil prices have surged to levels last seen over a year ago. The global Brent benchmark hit US$63/b, while its American counterpart WTI crested over the US$60/b mark. The more optimistic in the market see these gains as a start of a commodity supercycle stemming from market forces pent-up over the long Covid-19 pandemic. The more cynical see it as a short-term spike from a perfect winter storm and constrained supply. So, which is it?
To get to that point, let’s examine how crude oil prices have evolved since the start of the year. On the consumption side, the market is vacillating between hopeful recovery and jittery reactions as Covid-19 outbreaks and vaccinations lent a start-stop rhythm to consumption trends. Yes, vaccination programmes were developed at lightning speed; and even plenty of bureaucratic hiccoughs have not hampered a steady rollout across the globe. In the UK, more than 20% of adults have received at least one dose of the vaccines, with the USA not too far behind. Israel has vaccinated more than 75% of its population, and most countries should be well into their own programmes by the end of March. That acceleration of vaccinations has underpinned expectations of higher oil demand, with hopes that people will begin to drive again, fly again and buy again. But those hopes have been occasionally interrupted by new Covid-19 clusters detected and, more worryingly, new mutations of the virus.
Against this hopeful demand picture, supply has been managed. Squabbling among the OPEC+ club has prevented a more aggressive approach to managing supply than kingpin Saudi Arabia would like, but OPEC+ has still managed to hold itself together to placate the market that crude spigots will remain restrained. And while the UAE has successfully shifted OPEC+ quota plan for 2021 from quarterly adjustments to monthly, Saudi Arabia stepped into the vacuum to stamp its authority with a voluntary 1 million barrels per day cut. The market was impressed.
That combination of events over January was enough to move Brent prices from the low US$50/b level to the upper US$50/b range. However, US$60/b remained seemingly out of reach. It took a heavy dusting of snow across Texas to achieve that.
Winter weather across the northern hemisphere seemed harsher than usual this year. Europe was hit by two large continent-wide storms, while the American Northeast and Pacific Northwest were buffeted with quite a few snowstorms. Temperatures in East Asia were fairly cold too, which led to strong prices for natural gas and LNG to keep the population warm. But it was a major snowstorm that swept through the southern United States – including Texas – that had the largest effect on prices. Some areas of Texas saw temperatures as low as -18 degrees Celsius, while electricity demand surged to the point where grids failed, leaving 4.3 million people without power. A national emergency was declared, with over 150 million Americans under winter storm warning conditions.
For the global oil complex, the effects of the storm were also direct. Some of the largest oil refineries in the world were forced to shut down due to the Arctic conditions, further disrupting power and fuel supplies. All in all, over 3 mmb/d of oil processing capacity had to be idled in the wake of the storm, including Motiva’s Port Arthur, ExxonMobil’s Baytown and Marathon’s Galveston Bay refineries. And even if the sites were still running, they would have to contend to upstream disruptions: estimates suggest that crude oil production in the prolific Permian Basin dropped by over a million barrels per day due to power outages, while several key pipelines connecting Cushing, Oklahoma to the Texas Gulf Coast were also forced to shutter.
That perfect storm was enough to send crude prices above the US$60/b level. But will it last? The damage from the Texan snowstorm has already begun to abate, and even then crude prices did not seem to have the appetite to push higher than US$63/b for Brent and US$60/b for WTI.
Instead, the key development that should determine the future range for crude prices going into the second quarter of 2021 will be in early March, when the OPEC+ club meets once again to decide the level of its supply quotas for April and perhaps beyond. The conundrum facing the various factions within the club is this: at US$60/b, crude oil prices are not low enough to scare all members in voting for unanimous stricter quotas and also not high enough to rescind controlled supply. Instead, prices are at a fragile level where arguments can be made both ways. Russia is already claiming that global oil markets are ‘balanced’, while Saudi Arabia is emphasising the need for caution in public messaging ahead of the meeting. Saudi Arabia’s voluntary supply cut will also expire in March, setting up the stage for yet another fractious meeting. If a snow overrun Texans was a perfect storm to push crude prices to a 13-month high, then the upcoming OPEC+ meeting faces another perfect storm that could negate confidence. Which will it be? The answer lies on the other side of the storm.
Much like the year itself, the final quarter of 2020 proved to be full of shocks and surprises… at least in terms of financial results from oil and gas giants. With crude oil prices recovering on the back of a concerted effort by OPEC+ to keep a lid on supply, even at the detriment of their market share, the fourth quarter of 2020 was supposed to be smooth sailing. The tailwind of stronger crude and commodity prices, alongside gradual demand recovery, was expected to have smoothen out the revenue and profit curves for the supermajors.
That didn’t happen.
Instead, losses were declared where they were not expected. And where profits were to be had, they were meagre in volume. And crucially, a deeper dive into the financial results revealed worrying trends in the cash flow of several supermajors, calling into question the ability of these giants to continue on their capital expenditure and dividend plans, and the risks of resorting to debt financing in order to appease investors and yet also continue expanding.
Let’s start with the least surprising result of all. For months, ExxonMobil had been signalling that it would be taking a massive writedown on its upstream assets in Q4 2020, which could lead to a net loss for the quarter and the year. Unlike its peers, ExxonMobil had resisted making writedowns on the value of its crude-producing assets earlier in 2020. At the time, it stated that it had already built caution in the value assessments of those assets, reflecting ‘fair value’; not so long after that bold statement, ExxonMobil has been forced to backtrack and make a US$20.2 billion downward adjustment. Unusually, that meant that non-cash impairments aside, ExxonMobil actually eked out a tiny profit of US$110 million for the quarter on the strength of margins in the chemicals segment, but a full year loss of US$22.4 billion: the first ever annual loss since Exxon and Mobil merged in 1998. This was better than expected by Wall Street analysts, who would also be cheering the formation of ExxonMobil Low Carbon Solutions, in which the group would pump some US$3 billion through 2025 to reduce its greenhouse gas emissions by 20% from 2016 levels. That acknowledgement of a carbon neutral future is still far less ambitious than its European counterparts, but is a clear sign that ExxonMobil is starting to take the climate change element of its business more seriously.
If ExxonMobil managed to surprise in a good way, then its closest American rival did the opposite. Chevron had been outperforming ExxonMobil in quarterly results for a while now, but in Q4 2020 retreated with a net loss of US$665 million. That was narrower than the US$6.6 billion loss declared in Q4 2019, but still a shock since analysts were expecting a narrow profit. Calling 2020 ‘a year like no other’, the headwinds facing Chevron in Q4 2020 were the same facing all majors and supermajors, despite gains in crude prices, refining margins and fuel sales were still soft. Chevron’s cash flow was also a concern – as was ExxonMobil’s – which prompted chatter that the two direct descendants of JD Rockefeller’s Standard Oil were considering a merger. If so, then there is at least alignment on the climate topic: Chevron is also following the trail blazed by European supermajors in embracing a carbon neutral future, with CEO Michael Wirth conceding that Chevron may ‘not be an oil-first company in 2040’.
On the European side of the pond, that same theme of lowered downstream performance dragging down overall performance continued. But unlike the US supermajors, the likes of Shell, BP and Total were somewhat insulated from the Covid-19 blows at the peak of the pandemic as their opportunistic trading divisions capitalised on the wild swings in crude and fuel prices. That factor is now absent, with crude prices taking on a steady upward curve. That’s good for the rest of their businesses, but bad for trading, which thrives on uncertainty and volatility. And so BP reported a Q4 net profit of US$115 million, Shell followed with a Q4 net profit of US$393 million and Total closed out the earning season with industry-beating Q4 net profit of US$1.3 billion, above market expectations.
The softness of the financials hasn’t stopped dividend payouts, but has also been used by Europe’s Big Oil to set the tone for the next few decades of their existence. Total and BP paid a hefty premium to secure rights to build the next generation of UK wind farms; Total joined the Maersk-McKinney Moller Center for Zero Carbon Shipping to develop carbon neutral shipping solutions and splashed out on acquiring 2.2 GW of solar power projects in Texas; BP signed a strategic collaboration agreement with Russia’s Rosneft to develop new low carbon solutions; and aircraft carrier KLM took off with the first flight powered by synthetic kerosene that was developed by Shell through carbon dioxide, water and renewables. That’s a lot of a groundwork laid for the future where these giants can be carbon neutral by 2050.
The message from Q4 seems clear. Big Oil has barely begun its recovery from the Covid-19 maelstrom, and the road to a new normal remains long and painful. But this is also an opportunity to pivot; to set a new destination that is no longer business-as-usual, but embraces zero carbon ambitions. Even the American supermajors are slowly coming around, while the European continues to lead. Will majors in Asia, Latin America and Africa/Middle East follow? Let’s see what that attitude will bring over this new decade.
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