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Last Updated: June 26, 2020
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Overview 

  • Nigeria is the largest oil producer in Africa. It holds the largest natural gas reserves on the continent and was the world’s fifth–largest exporter of liquefied natural gas (LNG) in 2018.[1] Although Nigeria is the leading crude oil producer in Africa, production is affected by sporadic supply disruptions.
  • Nigeria’s crude oil and natural gas resources are the mainstay of the country’s economy. Because Nigeria heavily depends on oil revenue, its economy is noticeably affected by crude oil price changes. The International Monetary Fund (IMF) projects that Nigeria’s crude oil and natural gas exports earned $55 billion in 2018, which is $23 billion higher than in 2016.[2] The growth in export revenue, which can be partly attributed to the rebound in crude oil prices, has helped improve Nigeria’s fiscal position. However, Nigeria’s fiscal deficit remained flat at 4% of its gross domestic product (GDP) because of a significant increase in capital expenditures and lower–than–expected non–oil revenue collection, in spite of improvements to the country’s tax administration. The Nigerian government still heavily relies on crude oil and natural gas revenue; its non–oil revenue comprises only 3.4% of GDP, one of the lowest in the world.[3]


Sector organization

Recent updates

  • In September 2018, President Muhammadu Buhari vetoed the Petroleum Industry Governance Bill (PIGB) that was passed by the legislature in March 2018, which delayed efforts to liberalize the oil and natural gas sector and restructure the Nigerian National Petroleum Corporation (NNPC). The PIGB is one of four separate bills that were taken from the previous version, the Petroleum Industry Bill (PIB). Latest reports indicate that the National Assembly is drafting a new version of the PIB and is hoping to pass the bill by the end of 2020, although when or if this action will occur is unclear.[4]
  • The Nigerian government passed the Finance Act 2020 in January 2020. This act amends a number of tax laws and is aimed at improving tax participation and collection and modernizing the tax system. Provisions in the bill, such as the Petroleum Profits Tax (which repeals a tax exemption for dividends paid from after–tax profits), a value–added tax (which increases from 5% to 7.5%), and the Companies Income Tax (which requires Nigerian companies to deduct and withhold tax on payments to any foreign company that provides them with technical or professional services), are likely to affect oil and natural gas companies and increase their overall cost of doing business in the country.[5]
  • The Finance 2020 Act follows a November 2019 amendment to the 1999 Deep Offshore and Inland Basin Production Sharing Contracts Act, which changed royalty rates for deepwater (specifically greater than 200 meters in water depth) and inland basin contracts (which comprise onshore basins aside from the Niger Delta) to 10% and 7.5%, respectively. The amendment also introduces an additional royalty tax rate that ranges from 0% to 10% based on the price of crude oil. Given that international oil companies (IOCs) primarily operate in the deepwater fields in Nigeria, this amendment is likely to increase government’s share of revenue generated from these fields and to lead investors to re–evaluate their investment plans for currently producing fields as well as new–source development.[6]


Petroleum and other liquids

Exploration and production

  • According to the Oil & Gas Journal, Nigeria had an estimated 37.0 billion barrels of proved crude oil reserves by the end of 2019–the second–largest amount in Africa after Libya.[7] The majority of reserves are along the country’s Niger River Delta and offshore in the Bight of Benin, the Gulf of Guinea, and the Bight of Bonny.
  • As a member of the Organization of the Petroleum Exporting Countries (OPEC), Nigeria renewed its commitment to reduce crude oil production in April 2020, capping its production at 1.41 million barrels per day (b/d).[8] The agreement takes effect on May 1, 2020, and ends on April 30, 2022.[9] However, Nigeria’s compliance with the OPEC+ agreement has been intermittent; the country has at times produced more than the agreed-upon quota in the past. In addition, Nigeria has designated some of its crude oil streams as lease condensate, which is not subject to the OPEC+ agreement production cuts, which allows Nigeria to circumvent its obligation to reduce production.
  • In 2019, Nigeria produced about 2.0 million b/d of petroleum and other liquids, of which 1.65 million b/d was crude oil. The remainder is composed of natural gas plant liquids, other liquids, and refinery processing gains[10] (Figure 1).
  • The deepwater Egina project was the latest significant field to come online in Nigeria. The Egina field came online in January 2019 and reached its peak production plateau of 200,000 b/d at the end of 2019. The Nigerian minister of petroleum, Emmanuel Kachikwu, has labeled Egina crude oil as a condensate, in spite of its API gravity and sulfur content being specified at 27° and 0.17%, respectively, a crude oil assay that would place it in the medium, sweet categories.[11]
  • Smaller fields, such as the offshore Gbetiokun field and the onshore Qua Ibo field in the eastern part of the Niger Delta, have provided marginal increases to Nigeria’s crude oil production in the past year.[12] These projects have helped to partially offset production declines at Nigeria’s older, more mature fields. Other planned deepwater projects have been repeatedly delayed because of regulatory uncertainty surrounding the PIB. In addition, the recent deepwater royalty tax increase may further inhibit investor interest in exploration and development of new offshore fields.
  • Exploration activities have largely focused in deepwater and ultra-deepwater offshore fields, partially as a result of security concerns onshore, and many IOCs have divested their onshore assets. The NNPC plans to launch a new crude oil licensing round in mid–2020, although the licensing round will likely be postponed until after the PIB legislation issue is resolved later this year. Whether or not there will be sufficient investor interest if the PIB does not pass is unclear, given the recent amendments to the royalty tax structure for deepwater production.[13]


Refining and refined oil products

  • Nigeria relies on imports of petroleum products to meet domestic demand, importing about 442,000 b/d of petroleum products in 2018.[14]
  • The country has three major crude oil refineries (Port Harcourt I and II, Warri, and Kaduna) and has a total crude oil distillation capacity of 423,750 b/d, according to the Oil & Gas Journal.[15] All three refineries are run by the state–owned national oil company (NOC), NNPC. These refineries persistently operate at far lower than full capacity because of operational failures, fires, and sabotage, mainly on the crude oil pipelines feeding the refineries. NNPC has begun rehabilitation work at its refineries, and the NNPC’s latest reports indicate that the refineries have been shuttered. The rehabilitation work is expected to be completed by 2022, although how much throughput the refineries will have after rehabilitation is unclear. NNPC stated in April 2020 that it will no longer run the refineries after rehabilitation and is reportedly seeking a private sector company to manage operations at the refineries.[16]
  • A small, privately owned refinery located in Ogbele, Ahoada, in the Rivers state expanded its refining capacity to 6,000 b/d in January 2020. The expansions completed at the refinery will allow it to produce and market other fuels such as heavy residual fuel oil, marine diesel, and kerosene. Previously, diesel was the only petroleum product the refinery could produce. The refinery is owned by Niger Delta Petroleum Resources (NPDR), a subsidiary of Niger Delta Exploration and Production; NPDR plans to further increase the refinery’s capacity to 11,000 b/d in the future, although they have not released any concrete dates.[17]
  • Nigeria has a gas–to–liquids (GTL) plant at Escravos with a nameplate capacity of 33,000 b/d that started production in mid–2014, about a decade behind schedule. The Escravos GTL plant is operated by Chevron (75%) in partnership with NNPC (25%). The Escravos GTL plant can convert about 475 million cubic feet per day (MMcf/d) of natural gas into diesel, liquefied petroleum gas (LPG), and naphtha products, primarily for export.[18]
  • The Dangote Group, a Nigerian conglomerate, is constructing an integrated refining and petrochemical complex in the Lekki Free Trade Zone east of Lagos, Nigeria’s most populous city. The Dangote Group expects the refinery to come online by 2021, although the refinery is not likely to be completed on time.[19] According to the Oil & Gas Journal, the refining and petrochemical complex will have a 650,000 b/d crude oil distillation unit (making it the world’s largest single–train refinery), a 3.6 million ton per year polypropylene plant, a 3.0 million ton per year urea plant, and natural gas processing installations to feed in natural gas.[20] Once completed, it will be the largest refinery in Africa and is expected to significantly affect domestic and regional crude oil and petroleum products markets.


Petroleum and other liquids

According to the latest estimates by Global Trade Tracker, Nigeria exported about 2.08 million b/d of crude oil and condensate in 2019. India was the largest importer of Nigeria’s crude oil and condensate, purchasing about 420,000 b/d in 2019. Spain and the Netherlands were the next largest importers of Nigeria’s crude oil and condensate, each importing about 238,000 and 208,000 b/d in 2019, respectively. The United States was the fourth–largest importing country of Nigeria’s crude oil and condensate in 2019. Europe continued to be the largest importer by region, importing nearly 1 million b/d[21] (Figure 2).


Natural gasExploration and production


  • Nigeria had an estimated 200.4 trillion cubic feet (Tcf) of proved natural gas reserves by the end of 2019, according to the Oil & Gas Journal. Nigeria has the largest natural gas reserves in Africa.[22]
  • According to the latest estimates by EIA, Nigeria produced 1.6 Tcf of dry natural gas (or marketed natural gas production) in 2019.[23] Nigeria’s natural gas industry is also affected by the same security and regulatory issues that affect the crude oil industry.
  • A significant amount of Nigeria’s gross natural gas production is either re–injected or flared. Some of Nigeria’s oil fields lack the infrastructure to capture the natural gas produced with oil, known as associated gas. According to the most recent data by the World Bank’s Global Gas Flaring Reduction Partnership (GGFR), Nigeria flared about 261 billion cubic feet (Bcf) of natural gas in 2018, making Nigeria the seventh–largest natural gas flaring country in terms of annual natural gas flaring volume.[24]
  • In December 2019, Nigeria LNG (NLNG) reached financial close, or its final investment decision, to add a seventh train to its existing facility, adding about 365 Bcf, thus increasing the total capacity of the facility to 1.4 Tcf. The expansion project was initially proposed in 2005 but encountered numerous delays. NLNG expects the project to be completed by 2024, and it will be operated by Shell (25.6%), and the other shareholders are NNPC (49%), Total (15%), and Eni (10.4%)[25] (Figure 3).


Natural gas exports
  • Nigeria exports natural gas primarily as LNG. Both infrastructure and demand constraints are challenges to exporting primarily by pipeline to neighboring countries. Nigeria began exporting LNG in 1999 when the first two trains at the Bonny Island facility were completed.[26]
  • According to the latest estimates in BP’s 2019 Statistical Review of World Energy, Nigeria exported about 982 Bcf of LNG in 2018, ranking Nigeria as the world’s fifth–largest LNG exporter, behind Qatar, Australia, Malaysia, and the United States. Nigeria’s LNG exports accounted for about 6.5% of LNG traded globally. Spain was the largest importer of Nigeria’s LNG in 2018, importing about 146 Bcf of Nigeria’s LNG, followed by India (143 Bcf), and France (126 Bcf)[27] (Figure 4).


Energy consumption
  • According to EIA’s latest estimates, total primary energy consumption in Nigeria was about 1.5 quadrillion British thermal units in 2017. Most primary energy consumption in the country was derived from natural gas, petroleum, and other liquids (97%). Traditional biomass and waste (typically consisting of wood, charcoal, manure, and crop residues used for power generation), coal, and renewables accounted for only a marginal amount of consumption (3%) in 2017.[28]


Electricity
  • Nigeria’s generation capacity was 12,664 megawatts (MW) in 2017, of which 10,522 MW (83%) was from fossil fuels; 2,110 MW (17%) was from hydroelectricity; and 32 MW (1%) was from solar, wind, and biomass and waste. Net electricity generation was far lower than capacity and was 30.6 billion kilowatthours (3,495 MW) in 2017, or about 28% of total capacity.[29]
  • Although Nigeria is the continent’s largest economy, only 60% of the population had access to electricity in 2018, according to the latest estimates by the International Energy Agency. Most of Nigeria’s fossil fuel–derived electricity generation is from natural gas, and crude oil is mainly used for backup power generation. Nigeria’s power sector suffers from poor maintenance of electricity facilities, natural gas supply shortages, and an inadequate transmission and distribution network.[30]


Renewable Energy Sources
  • Nigeria has set ambitious goals to increase renewable power generation capacity. The Nigerian government has approved the contract to develop the 3.01 GW Mambilla hydropower plant located in the Taraba state. The Exim Bank of China will provide 85% of the required financing to develop the project, and the contract to construct the facility was awarded in November 2017 to a consortium of three Chinese companies, including the Gezhouba Group.[31] Other significant hydropower projects that are currently in development or construction include the 700 MW Zungeru hydropower project and the 40 MW Kashimbila hydropower project, which are currently under construction, and the rehabilitation of the 578 MW Jebba hydropower project and the 548 MW Kainji hydropower project. These projects are reportedly due to come online in the next two to three years, but whether the completion dates will be postponed because of project delays is still unclear.[32]
  • Government support and investor interest in solar power projects have been growing in the past few years in Nigeria, partially as a way to mitigate natural gas supply shortages and to increase access to electricity in remote and rural areas. The Nigerian government, the Rural Electrification Agency, and the World Bank–funded Nigeria Electrification Project are jointly funding a $75 million grant to encourage off–grid solar investments to reduce kerosene and diesel use for lighting and backup power generation.[33] In July 2016, Nigeria signed power purchase agreements with 14 utility–scale solar photovoltaic facilities that have a total generation capacity of 1.1 GW, although none of these projects has yet reached financial close, and reportedly the independent power producers and the Nigerian government have a dispute regarding tariff pricing.[34]

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U.S. oil and natural gas production to fall in 2021, then rise in 2022

U.S. monthly crude oil and natural gas production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)

In its January 2020 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that annual U.S. crude oil production will average 11.1 million b/d in 2021, down 0.2 million b/d from 2020 as result of a decline in drilling activity related to low oil prices. A production decline in 2021 would mark the second consecutive year of production declines. Responses to the COVID-19 pandemic led to supply and demand disruptions. EIA expects crude oil production to increase in 2022 by 0.4 million b/d because of increased drilling as prices remain at or near $50 per barrel (b).

The United States set annual natural gas production records in 2018 and 2019, largely because of increased drilling in shale and tight oil formations. The increase in production led to higher volumes of natural gas in storage and a decrease in natural gas prices. In 2020, marketed natural gas production fell by 2% from 2019 levels amid responses to COVID-19. EIA estimates that annual U.S. marketed natural gas production will decline another 2% to average 95.9 billion cubic feet per day (Bcf/d) in 2021. The fall in production will reverse in 2022, when EIA estimates that natural gas production will rise by 2% to 97.6 Bcf/d.

U.S. monthly crude oil production

Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)

EIA’s forecast for crude oil production is separated into three regions: the Lower 48 states excluding the Federal Gulf of Mexico (GOM) (81% of 2019 crude oil production), the GOM (15%), and Alaska (4%). EIA expects crude oil production in the U.S. Lower 48 states to decline through the first quarter of 2021 and then increase through the rest of the forecast period. As more new wells come online later in 2021, new well production will exceed the decline in legacy wells, driving the increase in overall crude oil production after the first quarter of 2021.

Associated natural gas production from oil-directed wells in the Permian Basin will fall because of lower West Texas Intermediate crude oil prices and reduced drilling activity in the first quarter of 2021. Natural gas production from dry regions such as Appalachia depends on the Henry Hub price. EIA forecasts the Henry Hub price will increase from $2.00 per million British thermal units (MMBtu) in 2020 to $3.01/MMBtu in 2021 and to $3.27/MMBtu in 2022, which will likely prompt an increase in Appalachia's natural gas production. However, natural gas production in Appalachia may be limited by pipeline constraints in 2021 if the Mountain Valley Pipeline (MVP) is delayed. The MVP is scheduled to enter service in late 2021, delivering natural gas from producing regions in northwestern West Virginia to southern Virginia. Natural gas takeaway capacity in the region is quickly filling up since the Atlantic Coast Pipeline was canceled in mid-2020.

January, 15 2021
So, Why Is Saudi Arabia Doing This?

Just when it seems that the drama of early December, when the nations of the OPEC+ club squabbled over how to implement and ease their collective supply quotas in 2021, would be repeated, a concession came from the most unlikely quarter of all. Saudi Arabia. OPEC’s swing producer and, especially in recent times, vocal judge, announced that it would voluntarily slash 1 million barrels per day of supply. The move took the oil markets by surprise, sending crude prices soaring but was also very unusual in that it was not even necessary at all.

After a day’s extension to the negotiations, the OPEC+ club had actually already agreed on the path forward for their supply deal through the remainder of Q1 2021. The nations of OPEC+ agreed to ease their overall supply quotas by 75,000 b/d in February and 120,000 b/d in March, bringing the total easing over three months to 695,000 b/d after the UAE spearheaded a revised increase of 500,000 b/d for January. The increases are actually very narrow ones; there were no adjustments for quotas for all OPEC+ members with the exception of Russia and Kazakshtan, who will be able to pump 195,000 additional barrels per day between them. That the increases for February and March were not higher or wider is a reflection of reality: despite Covid-19 vaccinations being rolled out globally, a new and more infectious variant of the coronavirus has started spreading across the world. In fact, there may even be at least of these mutations currently spreading, throwing into question the efficacy of vaccines and triggering new lockdowns. The original schedule of the April 2020 supply deal would have seen OPEC+ adding 2 million b/d of production from January 2021 onwards; the new tranches are far more measured and cognisant of the challenging market.

Then Saudi Arabia decides to shock the market by declaring that the Kingdom would slash an additional million barrels of crude supply above its current quota over February and March post-OPEC+ announcement. Which means that while countries such as Russia, the UAE and Nigeria are working to incrementally increase output, Saudi Arabia is actually subsidising those planned increases by making a massive additional voluntary cut. For a member that threw its weight around last year by unleashing taps to trigger a crude price war with Russia and has been emphasising the need for strict compliant by all members before allowing any collective increases to take place, this is uncharacteristic. Saudi Arabia may be OPEC’s swing producer, but it is certainly not that benevolent. Not least because it is expected to record a massive US$79 billion budget deficit for 2020 as low crude prices eat into the Kingdom’s finances.

So, why is Saudi Arabia doing this?

The last time the Saudis did this was in July 2020, when the severity of the Covid-19 pandemic was at devastating levels and crude prices needed some additional propping up. It succeeded. In January 2021, however, global crude prices are already at the US$50/b level and the market had already cheered the resolution of OPEC+’s positions for the next two months. There was no real urgent need to make voluntary cuts, especially since no other OPEC member would suit especially not the UAE with whom there has been a falling out.

The likeliest reason is leadership. Having failed to convince the rest of the OPEC+ gang to avoid any easing of quotas, Saudi Arabia could be wanting to prove its position by providing a measure of supply security at a time of major price sensitivity due to the Covid-19 resurgence. It will also provide some political ammunition for future negotiations when the group meets in March to decide plans for Q2 2021, turning this magnanimous move into an implicit threat. It could also be the case that Saudi Arabia is planning to pair its voluntary cut with field maintenance works, which would be a nice parallel to the usual refinery maintenance season in Asia where crude demand typically falls by 10-20% as units shut for routine inspections.

It could also be a projection of soft power. After isolating Qatar physically and economically since 2017 over accusations of terrorism support and proximity to Iran, four Middle Eastern states – Saudi Arabia, Bahrain, the UAE and Egypt – have agreed to restore and normalise ties with the peninsula. While acknowledging that a ‘trust deficit’ still remained, the accord avoids the awkward workarounds put in place to deal with the boycott and provides for road for cooperation ahead of a change on guard in the White House. Perhaps Qatar is even thinking of re-joining OPEC? As Saudi Arabia flexes its geopolitical muscle, it does need to pick its battles and re-assert its position. Showcasing political leadership as the world’s crude swing producer is as good a way of demonstrating that as any, even if it is planning to claim dues in the future.

It worked. It has successfully changed the market narrative from inter-OPEC+ squabbling to a more stabilised crude market. Saudi Arabia’s patience in prolonging this benevolent role is unknown, but for now, it has achieved what it wanted to achieve: return visibility to the Kingdom as the global oil leader, and having crude oil prices rise by nearly 10%.

Market Outlook:

  • Crude price trading range: Brent – US$55-57/b, WTI – US$51-53/b
  • Global crude oil benchmarks jumped several levels to a new higher range, as Saudi Arabia supplemented OPEC+’s decision to allow a minor increase in supply quotas for February and March with a massive 1 mmb/d voluntary cut over the same period
  • There are signs that the elevated level of crude pricing is tempting American drillers back to work, with Baker Hughes reporting a massive 67-site gain in active rigs over the first week of 2021; this will present another headache for OPEC+ when it comes time to debate the supply deal path forward for April and beyond
January, 14 2021
SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

  • This edition of the Short-Term Energy Outlook (STEO) is the first to include forecasts for 2022.
  • The January STEO remains subject to heightened levels of uncertainty because responses to COVID-19 continue to evolve. Reduced economic activity and changes to consumer behavior in response to the COVID-19 pandemic caused energy demand and supply to decline in 2020. The ongoing pandemic and the success of vaccination programs will continue to affect energy use in the future.
  • Economic assumptions are among the most important drivers of the U.S. Energy Information Administration’s (EIA) forecasts. EIA’s U.S. macroeconomic assumptions are based on forecasts by IHS Markit and EIA’s global economic assumptions are based on forecasts from Oxford Economics. After falling by 3.5% in 2020, IHS Markit forecasts that U.S. real gross domestic product (GDP) will increase by 4.2% in 2021 and 3.8% in 2022. Rising GDP contributes to EIA’s forecast of rising total energy use in the United States during 2021 and 2022. After falling by 7.8% in 2020, EIA forecasts that total U.S. energy consumption will rise by 2.6% in 2021 and by 2.5% in 2022, reaching 97.3 quadrillion British thermal units (quads), 3.0 quads less than in 2019.
  • EIA forecasts Brent crude oil spot prices to average $53 per barrel (b) in both 2021 and 2022 compared with an average of $42/b in 2020.
  • EIA estimates that global consumption of petroleum and liquid fuels averaged 92.2 million barrels per day (b/d) for all of 2020, down by 9.0 million b/d from 2019. EIA expects global liquid fuels consumption will grow by 5.6 million b/d in 2021 and 3.3 million b/d in 2022.
  • EIA forecasts crude oil production from the Organization of the Petroleum Exporting Countries (OPEC) will average 27.2 million b/d in 2021, up from an estimated 25.6 million b/d in 2020. Forecast growth in output reflects OPEC’s announced increases to production targets and continuing rise in Libya’s production. On January 5, 2021, OPEC and partner countries (OPEC+) announced that they will maintain the previously agreed-upon January 2021 production increase of 0.5 million b/d. The latest OPEC+ agreement also calls for production increases from Russia and Kazakhstan in February and March. However, additional voluntary cuts by Saudi Arabia for February and March result in lower overall OPEC+ production in early 2021. EIA forecasts that OPEC crude oil production will rise by 1.1 million b/d in 2022.
  • EIA estimates global liquid fuels inventories rose at a rate of 6.5 million b/d in the first half of 2020 before declining at a rate of 2.4 million b/d in the second half of 2020. EIA forecasts global inventories will continue to fall in the forecast, declining at a rate of 0.6 million b/d in 2021 and 0.5 million b/d in 2022.
  • U.S. regular gasoline retail prices averaged $2.18 per gallon (gal) in 2020, compared with an average of $2.60/gal in 2019. EIA forecasts motor gasoline prices to average $2.40/gal in 2021 and $2.42/gal in 2022 U.S. diesel fuel prices averaged $2.55/gal in 2020, compared with $3.06/gal in 2019, and EIA forecasts them to average $2.71/gal in 2021 and $2.74/gal in 2022.
  • EIA estimates that U.S. crude oil production fell from the 2019 record level of 12.2 million b/d to 11.3 million b/d in 2020. EIA expects that annual average production will fall to 11.1 million b/d in 2021 before rising to 11.5 million b/d in 2022.
  • U.S. liquid fuels consumption in 2020 averaged 18.1 million b/d, down 2.5 million b/d (12%) from 2019 consumption. EIA forecasts U.S. liquid fuels consumption will rise to 19.5 million b/d in 2021 and then to 20.5 million b/d in 2022 (almost equal to the 2019 level).
  • Henry Hub natural gas spot prices averaged $2.03 per million British thermal units (MMBtu) in 2020. EIA expects Henry Hub prices will rise to an annual average of $3.01/MMBtu in 2021, limiting natural gas use for power generation amid reduced natural gas production. EIA forecasts Henry Hub prices will rise to an average of $3.27/MMBtu in 2022.
  • U.S. working natural gas in storage ended October at more than 3.9 trillion cubic feet (Tcf), 5% more than the five-year (2015–19) average and the fourth-highest end-of-October level on record. EIA forecasts that declines in U.S. natural gas production this winter compared with last winter will more than offset the declines in natural gas consumption, which will contribute to inventory withdrawals outpacing the five-year average during the remainder of the winter, which ends in March. Forecast natural gas inventories end March 2021 at 1.6 Tcf, 12% lower than the 2016–20 average.
  • EIA estimates that U.S. natural gas consumption averaged 83.1 billion cubic feet per day (Bcf/d) in 2020, down 2.5% from 2019. EIA expects that natural gas consumption will decline by 2.8% in 2021 and by 2.1% in 2022. Most of the decline in natural gas consumption is the result of less natural gas use in the power sector, which EIA forecasts to decline because of rising natural gas prices. These declines are partly offset by rising natural gas use in other sectors.
  • EIA estimates that 2020 dry natural gas production averaged 90.8 Bcf/d, down 2.5% from 2019. EIA expects U.S. dry natural gas production to average 88.2 Bcf/d in 2021, down by 2.8% from 2020, and then rise to 89.7 Bcf/d in 2022.
  • EIA forecasts that total consumption of electricity in the United States will increase by 1.5% in 2021 after falling by 4.0% in 2020. The pandemic significantly affected electricity consumption in the commercial and industrial sectors in 2020. EIA estimates retail sales of electricity to the two sectors fell by 6.0% and 7.9%, respectively. EIA expects commercial electricity use in 2021 to rise by 0.9% and industrial electricity use to rise by 1.2%. Social distancing guidelines have caused people to spend more time at home, resulting in increased residential electricity use. In 2020, retail sales of electricity to the residential sector were 1.3% higher despite a mild winter earlier in the year. EIA expects residential electricity use will rise by 2.4% in 2021 as colder winter weather leads to more heating demand. Total forecast electricity consumption in 2022 will rise by 1.7%.
  • EIA expects the share of U.S. electric power sector generation from natural gas will decline from 39% in 2020 to 36% in 2021 and 34% in 2022 in response to significantly higher natural gas fuel costs and increased generation from renewable energy sources. Coal’s forecast share of electricity generation will rise from 20% in 2020 to 22% in 2021 and 24% in 2022, which is close to its share in 2019. Electricity generation from renewable energy sources will rise from 20% in 2020 to 21% in 2021 and 23% in 2022. The nuclear share of U.S. generation will decline from 21% in 2020 to 20% in 2021 and 19% in 2022.
  • During the next two years, EIA expects electricity generation capacity from renewable energy sources to continue growing. Although EIA expects both wind and solar capacity growth, solar capacity grows at a faster rate in the forecast. Based on EIA survey data, large-scale solar capacity growth in gigawatts (GW) will exceed wind growth for the first time in 2021.
  • EIA estimates that total U.S. coal production decreased by 24% to 537 million short tons (MMst) in 2020. This decline largely reflected lower demand for coal from the electric power sector and the coal export market. Lower natural gas prices made coal less competitive for power generation. In 2021, EIA expects coal production to increase by 12% to 603 MMst because of a forecast 41% increase in natural gas prices for electricity generators, making coal more competitive in the electric power sector. EIA forecasts coal production will rise to 628 MMst in 2022.
  • After declining by 11.1% in 2020, EIA forecasts that total energy-related carbon dioxide (CO2) emissions will increase by 4.7% in 2021 and by 3.2% in 2022. Even with growth over the next two years, forecast CO2 emissions in 2022 remain 3.9% lower than 2019 levels. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.


World liquid fuels production and consumption balance

U.S. natural gas prices


U.S. residential electricity price

January, 14 2021