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U.S. crude oil production in five AEO2019 cases

Source: U.S. Energy Information Administration, Annual Energy Outlook 2019

EIA’s Annual Energy Outlook 2019 (AEO2019) Reference case projects that U.S. tight oil production, which became the more common form of oil production in 2015, will continue to increase through 2030, ultimately reaching more than 10 million barrels per day (b/d) in the early 2030s. Tight oil production reached 6.5 million b/d in the United States in 2018, accounting for 61% of total U.S. production. EIA projects further U.S. tight oil production growth as the industry continues to improve drilling efficiencies and reduce costs, which makes developing tight oil resources less sensitive to oil prices than in the past.

U.S. crude oil production in the AEO2019 reference case

Source: U.S. Energy Information Administration, Annual Energy Outlook 2019

Recent growth in U.S. crude oil production has been driven by the development of tight oil resources, primarily in the Permian Basin in western Texas and eastern New Mexico. Three major tight oil plays in the Permian Basin—the Spraberry, Bone Spring, and Wolfcamp—accounted for 41% of U.S. tight oil production in 2018. In the AEO2019 Reference case, approximately half of cumulative tight oil production through 2050 is expected to come from these three plays. The Bakken and Eagle Ford plays also remain major contributors to U.S. tight oil supply through 2050, accounting for 19% and 17% of cumulative tight oil production, respectively.

However, future growth of domestic tight oil production depends on a variety of factors, including the quality of resources, technology and operational improvements that increase productivity and reduce costs, and market prices. AEO2019 includes several sensitivity cases that incorporate different assumptions regarding oil prices, technological improvement, and resource recoverability.

U.S. crude oil production in three AEO2019 cases

Source: U.S. Energy Information Administration, Annual Energy Outlook 2019

The High Oil and Gas Resource and Technology case uses more optimistic technology and resource assumptions than in the Reference case. In this case, U.S. tight oil production increases through the mid-2040s, as higher productivity reduces development and production costs, spurring additional resource development. Tight oil production slowly decreases toward the end of the projection period as drilling moves to less productive areas. Total U.S. oil production in 2050 in this case is nearly 19 million b/d, much higher than the Reference case level of about 12 million b/d.

In the Low Oil and Gas Resource and Technology case, which uses more pessimistic technology and resource assumptions than the Reference case, tight oil production still increases from its current level through the early 2020s before gradually declining through 2050. Total U.S. oil production in 2050 in this case falls to about 8 million b/d.

In these two sensitivity cases, technology and resource assumptions are modified, but the world oil prices are assumed to be the same as in the Reference case. The AEO2019 also contains two cases that assume higher and lower world oil prices under the same resource and technology assumptions as in the Reference case.

U.S. crude oil production in three AEO2019 cases

Source: U.S. Energy Information Administration, Annual Energy Outlook 2019

In the High Oil Price case, West Texas Intermediate spot prices rise rapidly from $68 per barrel in 2018 to more than $100 per barrel in 2019 and then gradually increase to $208 per barrel by 2050 (in 2018 dollars). As a result, total domestic crude oil production increases to almost 18 million b/d by 2024 before declining to 13 million b/d in 2050. This high oil price assumption results in the fastest near-term increase in tight oil production as higher prices speed up the pace of drilling. After the mid-2020s, tight oil production declines through 2050 as drilling moves to less productive areas.

In the Low Oil Price case, sustained low oil prices, averaging less than $50 per barrel through 2050, cause total domestic production to increase more slowly, from 10.9 million b/d in 2018 to nearly 13 million b/d in 2022, before gradually declining through the rest of the projection period. Tight oil production averages close to 6 million b/d in 2050, accounting for 69% of total domestic oil production.

production supply tight oil liquid fuels crude oil oil/petroleum
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The Impact of COVID 19 In The Downstream Oil & Gas Sector

Recent headlines on the oil industry have focused squarely on the upstream side: the amount of crude oil that is being produced and the resulting effect on oil prices, against a backdrop of the Covid-19 pandemic. But that is just one part of the supply chain. To be sold as final products, crude oil needs to be refined into its constituent fuels, each of which is facing its own crisis because of the overall demand destruction caused by the virus. And once the dust settles, the global refining industry will look very different.

Because even before the pandemic broke out, there was a surplus of refining capacity worldwide. According to the BP Statistical Review of World Energy 2019, global oil demand was some 99.85 mmb/d. However, this consumption figure includes substitute fuels – ethanol blended into US gasoline and biodiesel in Europe and parts of Asia – as well as chemical additives added on to fuels. While by no means an exact science, extrapolating oil demand to exclude this results in a global oil demand figure of some 95.44 mmb/d. In comparison, global refining capacity was just over 100 mmb/d. This overcapacity is intentional; since most refineries do not run at 100% utilisation all the time and many will shut down for scheduled maintenance periodically, global refining utilisation rates stand at about 85%.

Based on this, even accounting for differences in definitions and calculations, global oil demand and global oil refining supply is relatively evenly matched. However, demand is a fluid beast, while refineries are static. With the Covid-19 pandemic entering into its sixth month, the impact on fuels demand has been dramatic. Estimates suggest that global oil demand fell by as much as 20 mmb/d at its peak. In the early days of the crisis, refiners responded by slashing the production of jet fuel towards gasoline and diesel, as international air travel was one of the first victims of the virus. As national and sub-national lockdowns were introduced, demand destruction extended to transport fuels (gasoline, diesel, fuel oil), petrochemicals (naphtha, LPG) and  power generation (gasoil, fuel oil). Just as shutting down an oil rig can take weeks to complete, shutting down an entire oil refinery can take a similar timeframe – while still producing fuels that there is no demand for.

Refineries responded by slashing utilisation rates, and prioritising certain fuel types. In China, state oil refiners moved from running their sites at 90% to 40-50% at the peak of the Chinese outbreak; similar moves were made by key refiners in South Korea and Japan. With the lockdowns easing across most of Asia, refining runs have now increased, stimulating demand for crude oil. In Europe, where the virus hit hard and fast, refinery utilisation rates dropped as low as 10% in some cases, with some countries (Portugal, Italy) halting refining activities altogether. In the USA, now the hardest-hit country in the world, several refineries have been shuttered, with no timeline on if and when production will resume. But with lockdowns easing, and the summer driving season up ahead, refinery production is gradually increasing.

But even if the end of the Covid-19 crisis is near, it still doesn’t change the fundamental issue facing the refining industry – there is still too much capacity. The supply/demand balance shows that most regions are quite even in terms of consumption and refining capacity, with the exception of overcapacity in Europe and the former Soviet Union bloc. The regional balances do hide some interesting stories; Chinese refining capacity exceeds its consumption by over 2 mmb/d, and with the addition of 3 new mega-refineries in 2019, that gap increases even further. The only reason why the balance in Asia looks relatively even is because of oil demand ‘sinks’ such as Indonesia, Vietnam and Pakistan. Even in the US, the wealth of refining capacity on the Gulf Coast makes smaller refineries on the East and West coasts increasingly redundant.

Given this, the aftermath of the Covid-19 crisis will be the inevitable hastening of the current trend in the refining industry, the closure of small, simpler refineries in favour of large, complex and more modern refineries. On the chopping block will be many of the sub-50 kb/d refineries in Europe; because why run a loss-making refinery when the product can be imported for cheaper, even accounting for shipping costs from the Middle East or Asia? Smaller US refineries are at risk as well, along with legacy sites in the Middle East and Russia. Based on current trends, Europe alone could lose some 2 mmb/d of refining capacity by 2025. Rising oil prices and improvements in refining margins could ensure the continued survival of some vulnerable refineries, but that will only be a temporary measure. The trend is clear; out with the small, in with the big. Covid-19 will only amplify that. It may be a painful process, but in the grand scheme of things, it is also a necessary one.

Infographic: Global oil consumption and refining capacity (BP Statistical Review of World Energy 2019)

Region
Consumption (mmb/d)*
Refining Capacity (mmb/d)
North America

22.71

22.33

Latin America

6.5

5.98

Europe

14.27

15.68

CIS

4.0

8.16

Middle East

9.0

9.7

Africa

3.96

3.4

Asia-Pacific

35

34.75

Total

95.44

100.05

*Extrapolated to exclude additives and substitute fuels (ethanol, biodiesel)

Market Outlook:

  • Crude price trading range: Brent – US$33-37/b, WTI – US$30-33/b
  • Crude oil prices hold their recent gains, staying rangebound with demand gradually improving as lockdown slowly ease
  • Worries that global oil supply would increase after June - when the OPEC+ supply deal eases and higher prices bring back some free-market production - kept prices in check
  • Russia has signalled that it intends to ease back immediately in line with the supply deal, but Saudi Arabia and its allies are pushing for the 9.7 mmb/d cut to be extended to end-2020, putting the two oil producers on another collision course that previously resulted in a price war
  • Morgan Stanley expects Brent prices to rise to US$40/b by 4Q 2020, but cautioned that a full recovery was only likely to materialise in 2021

End of Article

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May, 31 2020
North American crude oil prices are closely, but not perfectly, connected

selected North American crude oil prices

Source: U.S. Energy Information Administration, based on Bloomberg L.P. data
Note: All prices except West Texas Intermediate (Cushing) are spot prices.

The New York Mercantile Exchange (NYMEX) front-month futures contract for West Texas Intermediate (WTI), the most heavily used crude oil price benchmark in North America, saw its largest and swiftest decline ever on April 20, 2020, dropping as low as -$40.32 per barrel (b) during intraday trading before closing at -$37.63/b. Prices have since recovered, and even though the market event proved short-lived, the incident is useful for highlighting the interconnectedness of the wider North American crude oil market.

Changes in the NYMEX WTI price can affect other price markers across North America because of physical market linkages such as pipelines—as with the WTI Midland price—or because a specific price is based on a formula—as with the Maya crude oil price. This interconnectedness led other North American crude oil spot price markers to also fall below zero on April 20, including WTI Midland, Mars, West Texas Sour (WTS), and Bakken Clearbrook. However, the usefulness of the NYMEX WTI to crude oil market participants as a reference price is limited by several factors.

pricing locations of selected North American crudes

Source: U.S. Energy Information Administration

First, NYMEX WTI is geographically specific because it is physically redeemed (or settled) at storage facilities located in Cushing, Oklahoma, and so it is influenced by events that may not reflect the wider market. The April 20 WTI price decline was driven in part by a local deficit of uncommitted crude oil storage capacity in Cushing. Similarly, while the price of the Bakken Guernsey marker declined to -$38.63/b, the price of Louisiana Light Sweet—a chemically comparable crude oil—decreased to $13.37/b.

Second, NYMEX WTI is chemically specific, meaning to be graded as WTI by NYMEX, a crude oil must fall within the acceptable ranges of 12 different physical characteristics such as density, sulfur content, acidity, and purity. NYMEX WTI can therefore be unsuitable as a price for crude oils with characteristics outside these specific ranges.

Finally, NYMEX WTI is time specific. As a futures contract, the price of a NYMEX WTI contract is the price to deliver 1,000 barrels of crude oil within a specific month in the future (typically at least 10 days). The last day of trading for the May 2020 contract, for instance, was April 21, with physical delivery occurring between May 1 and May 31. Some market participants, however, may prefer more immediate delivery than a NYMEX WTI futures contract provides. Consequently, these market participants will instead turn to shorter-term spot price alternatives.

Taken together, these attributes help to explain the variety of prices used in the North American crude oil market. These markers price most of the crude oils commonly used by U.S. buyers and cover a wide geographic area.

Principal contributor: Jesse Barnett

May, 28 2020
Financial Review: 2019

Key findings

  • Brent crude oil daily average prices were $64.16 per barrel in 2019—11% lower than 2018 levels
  • The 102 companies analyzed in this study increased their combined liquids and natural gas production 2% from 2018 to 2019
  • Proved reserves additions in 2019 were about the same as the 2010–18 annual average
  • Finding plus lifting costs increased 13% from 2018 to 2019
  • Occidental Petroleum’s acquisition of Anadarko Petroleum contributed to the largest reserve acquisition costs incurred for the group of companies since 2016
  • Refiners’ earnings per barrel declined slightly from 2018 to 2019

See entire annual review

May, 26 2020