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Last Updated: August 8, 2019
Business Trends

In the August 2019 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts relatively flat crude oil prices for the remainder of 2019 and through 2020 and a balanced global oil market in 2019 followed by modest inventory builds in 2020 as production growth outpaces consumption growth (Figure 1). In 2019, EIA forecasts that upward pressure on crude oil prices from supply-side constraints will be largely offset by demand-side concerns. In 2020, despite increased crude oil demand resulting from new regulations from the International Maritime Organization (IMO 2020), production is expected to increase more, offsetting the price impacts from increased demand. As a result of the offsetting price pressures, EIA forecasts that crude oil prices will remain relatively flat through 2020.

Figure 1. World liquid fuels production and consumption balance

Although EIA does not directly collect data on changes in global petroleum inventories, inventory data for the United States and other countries within the Organization for Economic Cooperation and Development (OECD) provide some insight into the global balance. In the August STEO, EIA forecasts that OECD inventories will average 2.9 billion barrels in 2019 and 3.0 billion barrels in 2020, 0.6% and 0.8% more than their trailing five-year averages, respectively. Inventories can also be measured on a days of supply basis, which more accurately represents the potential buffer that inventories offer from supply constraints. In 2019, EIA forecasts OECD inventories will average 60.8 days, 0.6 days (1.0%) lower than the previous five-year (2014–18) average. In 2020, EIA forecasts OECD inventories will average 61.6 days, 0.5 days (0.8%) lower than the previous five-year (2015–19) average.

Crude oil inventories have increased during the past decade, and EIA expects OECD inventory levels will remain higher through the forecast period than in the first half of the decade (2010–14), which averaged 57.7 days or 2.7 billion barrels (Figure 2). Inventory levels near or slightly lower than the trailing five-year (2014–18) average would still provide a larger buffer than 2010–14 average inventory levels. In the August STEO, EIA expects that inventory levels will remain near their five-year averages and therefore will have some moderating effect on crude oil prices.

Figure 2. OECD commerical oil inventories

In the August STEO, EIA forecasts 2020 inventory builds of 280,000 barrels per day (b/d), but that outcome is highly dependent on crude oil production. EIA forecasts that total global production growth will increase year over year by 1.6 million b/d in 2020. U.S. total liquids production drives the forecast global production growth, and EIA expects that it will average 19.8 million b/d in 2019 and increase by 1.5 million b/d to 21.3 million b/d in 2020.

EIA forecast that production from members of the Organization of the Petroleum Exporting Countries (OPEC) will decrease in 2019 and in 2020 and offset some of the production increases from the United States. OPEC members and non-OPEC participants (OPEC+) agreed to extend production cuts through the end of the first quarter of 2020. EIA’s forecast assumes the OPEC+ agreement will remain in place through the end of the first quarter of 2020, with OPEC+ continuing to target a balanced market thereafter. The compliance with production targets from the OPEC+ agreement will not only be a key determinant of whether global crude oil inventories remain near the five-year (2014–18) average during the forecast period but also a significant driver of crude oil prices. EIA forecasts OPEC total liquids production will average 35.3 million b/d in the second half of 2019 and 34.8 million b/d in 2020, down from 37.3 million b/d in 2018.

Declining OPEC production is the result of Saudi Arabia’s over compliance with the December 2018 OPEC+ agreement in the first half of 2019 and rapidly decreasing crude oil production in Iran and Venezuela. Combined production in Iran and Venezuela fell to an estimated 2.8 million b/d in July 2019, a 2.3 million b/d decrease compared with July 2018. The declines in these two countries contributed to OPEC’s crude oil production averaging 29.6 million b/d in July 2019, the lowest level since April 2014.

EIA estimates that Iran’s crude oil and condensate production has decreased by 1.8 million b/d since May 2018, when the United States announced its plan to withdraw from the Joint Comprehensive Plan of Action and reinstate sanctions in November 2018. EIA assumes that U.S. sanctions on Iran’s oil exports will remain in place through the end of the forecast period. Although Iran’s crude oil production declined at an average rate of 120,000 b/d per month since May 2018, EIA expects the decline rate to slow in the second half of 2019 as domestic Iranian consumption grows as a result of power plants switching from natural gas to crude oil for electric power generation.

The United States recently extended the time period for several companies to continue operations in Venezuela involving state-owned Petróleos de Venezuela (PdVSA) by three months to October 25, 2019. This extension should provide some short-term continuity for crude oil production operations there; however, U.S. sanctions will still limit the production from Venezuela’s energy sector. Additionally, the possibility of energy sector disruptions remain and could remove crude oil from the global markets.

Markets have already incorporated some geopolitical risk from supply disruptions into crude oil prices, but additional disruptions may remove large volumes of crude oil from the global market and cause crude oil prices to increase. In Libya, supply disruptions remain a significant risk through 2020 because of the tentative security situation in the country and the lack of investment in existing infrastructure. Disruptions to shipping through the Strait of Hormuz could also cause crude oil prices to increase. In recent weeks, Iran has seized crude oil tankers in the Strait; however, crude oil transit in the region has not been significantly disrupted to date.

The August STEO reflects potential downside risks to both supply and demand. Based on forecasts from Oxford Economics, EIA lowered its global oil-weighted gross domestic product (GDP) growth projection to 2.1% in 2019 in the August STEO, down from 2.2% in the July STEO. International trade tensions are also contributing to demand-side concerns. On August 1, Brent and West Texas Intermediate (WTI) prices declined by more than 7% on the day following the U.S. announcement of new tariffs on China. EIA revised its global demand forecast down by 100,000 b/d to 100.9 million b/d in 2019 because of the downside risks to demand. Crude oil prices are also lower than previously expected, which, in combination with the downside demand risks, contributed to a lower forecast price for Brent crude oil in the August STEO. EIA’s August STEO forecasts that Brent crude oil will average $65 per barrel (b) in both 2019 and 2020, $1/b lower in 2019 and $2/b lower in 2020 compared with the July STEO.

Figure 3. Brent crude oil price forecast

EIA expects Brent crude oil prices will increase to $65/b during the next several months and remain there throughout 2020. As previously discussed, EIA expects this price to be a relatively stable price point for the market, considering modest levels of inventory growth in 2020 and IMO 2020 regulations going into effect. However, the combination of oil supply disruption risk and lower economic growth expectations in 2019 creates uncertainty in EIA’s crude oil price forecast. Given the uncertainty in these risk factors, prices could break out of the mid-$60/b range if the supply or demand concerns materialize in the coming months.

U.S. average regular gasoline and diesel prices fall

The U.S. average regular gasoline retail price decreased nearly 3 cents from the previous week to $2.69 per gallon on August 5, 16 cents lower than the same time last year. The Gulf Coast price fell nearly 4 cents to $2.39 per gallon, the East Coast price fell 3 cents $2.60 per gallon, the Midwest price fell nearly 3 cents to $2.63 per gallon, the West Coast price fell more than 1 cent to $3.29 per gallon, and the Rocky Mountain price fell nearly 1 cent to $2.70 per gallon.

The U.S. average diesel fuel price fell less than 1 cent, remaining at $3.03 per gallon on August 5, 19 cents lower than a year ago. The Gulf Coast price fell nearly 1 cent, remaining at $2.79 per gallon, and the West Coast, East Coast, and Rocky Mountain prices each fell less than 1 cent, remaining at $3.61 per gallon, $3.06 per gallon, and $2.97 per gallon, respectively. The Midwest price increased less than 1 cent, remaining at $2.94 per gallon

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 2.9 million barrels last week to 83.3 million barrels as of August 2, 2019, 6.8 million barrels (8.8%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Gulf Coast, Midwest, and East Coast inventories increased by 2.0 million barrels, 0.5 million barrels, and 0.4 million barrels, respectively, while Rocky Mountain/West Coast inventories increased slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 4.9% of total propane/propylene inventories.

For questions about This Week in Petroleum, contact the Petroleum Markets Team at 202-586-4522.

consumption demand crude oil prices production supply STEO EIA
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Your Weekly Update: 12 - 16 August 2019

Market Watch 

Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b

  • Saudi Arabia’s overtures to further stabilise prices was met with a largely positive response by the market, allowing crude prices to claw back some ground after being hammered by demand concerns
  • Saudi officials reportedly called other members in the OPEC and OPEC+ producer clubs to discuss options on how to stem the recent rout in prices, with an anonymous official quoted as saying that it ‘would not tolerate continued price weakness’
  • Reports suggest that Saudi Arabia plans to keep its oil exports at below 7 mmb/d in September according to sales allocations, which was seen as a stabilising factor in crude price trends
  • This came after crude prices fell as the US-China trade war entered a new front, causing weakness in the Chinese Yuan, although President Trump has floated the idea of delaying the new round of tariffs beyond the current implementation timeline of September 1
  • Crude had also fallen in response to a slide in American crude oil stockpiles and a receding level of tensions in the Persian Gulf
  • In a new report, the International Energy Agency said that the outlook for global oil demand is ‘fragile’ on signs of an economic slowdown; there is also concern that China will target US crude if the US moves ahead with its tariff plan
  • The US active rig count lost another 8 rigs – 6 oil and 2 gas – the sixth consecutive weekly loss that brought the total number of active rigs to 934
  • Demand fears will continue to haunt the market, which will not be offset so easily of Saudi-led efforts to limit production; as a result, crude prices will trade rangebound with a negative slant in the US$56-58/b range for Brent and US$52-54/b for WTI

Headlines of the week


  • Nearly all Anadarko shareholders have approved the Occidental Petroleum deal, completing the controversial takeover bid despite investor Carl Icahn’s attempts to derail the purchase
  • Crude oil inventories in Western Canada have fallen by 2.75 million barrels m-o-m to its lowest level since November 2017, as the production limits in Alberta appear to be doing their job in limiting a supply glut while output curbs are slowly being loosened on the arrival of more rail and pipeline capacity
  • Mid-sized Colorado players PDC Energy and SRC Energy – both active in the Denver-Julesburg Basin – are reportedly in discussion to merge their operations
  • Pemex has been granted approval by the National Hydrocarbon Commission to invest US$10 billion over 25 years to develop onshore and offshore exploration opportunities in Mexico
  • Qatar Investment Authority has acquired a ‘significant stake’ in major Permian player Oryx Midstream Services from Stonepeak Infrastructure Partners for some US$550 million, as foreign investment in the basin increases
  • PDVSA and CNPC’s Venezuelan joint venture Sinovensa has announced plans to expand blending capacity – lightening up extra-heavy Orinoco crude to medium-grade Merey – from a current 110,000 b/d to 165,000 b/d
  • BHP has approved an additional US$283 million in funding for the Ruby oil and gas project in Trinidad and Tobago, with first production expected in 2021
  • CNPC, ONGC Videsh and Petronas have reportedly walked away from their onshore acreage in Sudan, blaming unpaid oil dues on production from onshore Blocks 2A and 4 that have already reached more than US$500 million


  • Expected completion of Nigeria’s huge planned 650 kb/d Dangote refinery has been delayed to the end of 2020, with issues importing steel and equipment cited
  • Saudi Aramco’s US refining arm Motiva announced plans to shut several key units at its 607 kb/d Port Arthur facility in Texas for a 2-month planned maintenance, affecting its 325 kb/d CDU and the naphtha processing plant
  • ADNOC has purchased a 10% stake in global terminal operator VTTI, expanding its terminalling capacity in Asia, Africa and Europe
  • A little-known Chinese contractor Wison Engineering Services has reportedly agreed to refurbish Venezuela’s main refineries in a barter deal for oil produced, in a bid for Venezuela to evade the current US sanctions on its crude exports
  • Swiss downstream player Varo Energy will increase its stake in the 229 kb/d Bayernoil complex in Germany to 55% after purchasing BP’s 10% stake
  • India has raised the projected cost estimate of its giant planned refinery in Maharashtra – a joint venture between Indian state oil firms with Saudi Aramco and ADNOC – to US$60 billion, after farmer protests forced a relocation

Natural Gas/LNG

  • The government of Australia’s New South Wales has given its backing to South Korea’s Epik and its plan to build a new LNG import terminal in Newcastle
  • Kosmos Energy is proposing to build two new LNG facilities to tap into deepwater gas resources offshore Mauritania and Senegal under development
  • In the middle of the Pacific, the French territory of New Caledonia has started work on its Centrale Pays Project, a floating LNG terminal with an accompanying 200-megawatt power plant, with Nouvelle-Caledonia Energie seeking a 15-year LNG sales contract for roughly 200,000 tons per year
August, 16 2019
The State of the Industry: Q2 2019

The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.

In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.

As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.

 After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.

And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.

So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.

Supermajor Financials: Q2 2019

  • ExxonMobil – Revenue (US$69.1 billion, down 6% y-o-y), Net profit (US$3.1 billion, down 22.5% y-o-y)
  • Shell - Revenue (US$90.5 billion, down 6.5% y-o-y), Net profit (US$3 billion, down 50% y-o-y)
  • Chevron – Revenue (US$36.3 billion, down 10.4% y-o-y), Net profit (US$4.3 billion, up 26% y-o-y)
  • BP - Revenue (US$73.7 billion, down 4.11% y-o-y), Net profit (US$2.8 billion, flat y-o-y)
  • Total - Revenue (US$51.2 billion, down 2.5% y-o-y), Net profit (US$2.89 billion, down 18.6% y-o-y)
August, 14 2019
TODAY IN ENERGY: Australia is on track to become world’s largest LNG exporter

LNG exports from selected countries

Source: U.S. Energy Information Administration, CEDIGAZ, Global Trade Tracker

Australia is on track to surpass Qatar as the world’s largest liquefied natural gas (LNG) exporter, according to Australia’s Department of Industry, Innovation, and Science (DIIS). Australia already surpasses Qatar in LNG export capacity and exported more LNG than Qatar in November 2018 and April 2019. Within the next year, as Australia’s newly commissioned projects ramp up and operate at full capacity, EIA expects Australia to consistently export more LNG than Qatar.

Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) in 2011 to more than 11.4 Bcf/d in 2019. Australia’s DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d by 2020–21 once the recently commissioned Wheatstone, Ichthys, and Prelude floating LNG (FLNG) projects ramp up to full production. Prelude FLNG, a barge located offshore in northwestern Australia, was the last of the eight new LNG export projects that came online in Australia in 2012 through 2018 as part of a major LNG capacity buildout.

Australia LNG export capacity

Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL), trade press
Note: Project’s online date reflects shipment of the first LNG cargo. North West Shelf Trains 1–2 have been in operation since 1989, Train 3 since 1992, Train 4 since 2004, and Train 5 since 2008.

Starting in 2012, five LNG export projects were developed in northwestern Australia: onshore projects Pluto, Gorgon, Wheatstone, and Ichthys, and the offshore Prelude FLNG. The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In eastern Australia, three LNG export projects were completed in 2015 and 2016 on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.4 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane as a feedstock to produce LNG.

Australia LNG projects

Source: U.S. Energy Information Administration

Most of Australia’s LNG is exported under long-term contracts to three countries: Japan, China, and South Korea. An increasing share of Australia’s LNG exports in recent years has been sent to China to serve its growing natural gas demand. The remaining volumes were almost entirely exported to other countries in Asia, with occasional small volumes exported to destinations outside of Asia.

Australia LNG exports by destination country

Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL)

For several years, Australia’s natural gas markets in eastern states have been experiencing natural gas shortages and increasing prices because coal-bed methane production at some LNG export facilities in Queensland has not been meeting LNG export commitments. During these shortfalls, project developers have been supplementing their own production with natural gas purchased from the domestic market. The Australian government implemented several initiatives to address domestic natural gas production shortages in eastern states.

Several private companies proposed to develop LNG import terminals in southeastern Australia. Of the five proposed LNG import projects, Port Kembla LNG (proposed import capacity of 0.3 Bcf/d) is in the most advanced stage, having secured the necessary siting permits and an offtake contract with Australian customers. If built, the Port Kembla project will use the floating storage and regasification unit (FSRU) Höegh Galleon starting in January 2021.

August, 14 2019