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Last Updated: September 19, 2019
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On Saturday, September 14, 2019, an attack damaged the Saudi Aramco Abqaiq oil processing facility and the Khurais oil field in eastern Saudi Arabia. The Abqaiq oil processing facility is the world’s largest crude oil processing and stabilization plant with a capacity of 7 million barrels per day (b/d), equivalent to about 7% of global crude oil production capacity. On Monday, September 16, 2019, the first full day of trading after the attack, Brent and West Texas Intermediate (WTI) crude oil prices experienced the largest single-day price increase since August 21, 2008 and June 29, 2012, respectively.

On Tuesday, September 17, Saudi Aramco reported that Abqaiq was producing 2 million b/d and that its entire output capacity was expected to be fully restored by the end of September. Additionally, Saudi Aramco stated that crude oil exports to customers will continue by drawing on existing inventories and offering additional crude oil production from other fields. Tanker loading estimates from third-party data sources indicate that loadings at two Saudi Arabian export facilities were restored to the pre-attack levels. Likely driven by news of the expected return of the lost production capacity both Brent and WTI crude oil prices fell on Tuesday, September 17.

Crude oil markets will certainly continue to react to new information as it becomes available in the days and weeks ahead, but this disruption and the resulting changes in global crude oil prices will influence U.S. retail gasoline prices.

The U.S. Energy Information Administration (EIA) estimates that Saudi Arabia was producing 9.9 million b/d of crude oil in August, and estimates from the Joint Organizations Data Initiative (JODI) indicate the country exported 6.9 million b/d during July, the latest month for which data are available (Figure 1). Estimates from a third-party tanker tracking data service, ClipperData, indicate Saudi Arabian crude oil exports in August remained at 6.7 million b/d. These crude oil production and export levels are each 0.5 million b/d lower than their respective 2018 annual averages. JODI data indicate that Saudi Arabia held nearly 180 million barrels of crude oil in inventory at the end of July 2019. Saudi Arabia can use these inventories to maintain a similar level of crude oil exports as before the strike, assuming the production outage is short in duration, as indicated by Saudi Aramco’s update on September 17.

Figure 1. Saudi Arabia crude oil production and exports

Saudi Arabia is rare among oil producing countries, in that it regularly maintains spare crude oil production capacity as a matter of its oil production policy. EIA defines spare capacity as the volume of production that can be brought online within 30 days and sustained for at least 90 days using sound business practices. In the September Short-Term Energy Outlook (STEO) EIA estimated that the Organization of the Petroleum Exporting Countries (OPEC) spare capacity was 2.2 million b/d in August 2019, nearly all of which was in Saudi Arabia. Outside of OPEC, EIA does not include any unused capacity in its spare capacity total, even when countries periodically hold such capacity (as is the case with Russia). During previous periods of significant oil supply disruptions, Saudi Arabia generally increased production to offset the loss of supplies and stabilize markets (Figure 2).

Figure 2. OPEC spare capacity and Brent crude oil price

Following the September 14 attack and an ensuing outage at the Abqaiq facility, the amount of available spare capacity that can be brought online within 30 days in Saudi Arabia is unknown. In addition, because Saudi Arabia holds most of OPEC’s spare capacity, there is likely little spare production capacity elsewhere to offset the loss. Russia may be able to increase production in response to disruption and higher prices, but the amount of time needed for these volumes to become available is uncertain. The United States would also likely be able to increase production, but it would take longer than 30 days. Therefore, without Saudi Arabian spare capacity, the global crude oil market is vulnerable to production outages, as events would be more disruptive than normal.

The most readily available alternative source of supply during a supply outage is stocks of crude oil. As of September 1, commercial inventories of crude oil and other liquids for Organization for Economic Cooperation and Development (OECD) members were estimated at 2.9 billion barrels, enough to cover 61 days of its members’ liquid fuels consumption. On a days-of-supply basis, OECD commercial inventories are 2% lower than the five-year (2014-18) average (Figure 3).

Figure 3. OECD commerical oil inventories days of supply

The United States has two types of crude oil inventories: those that private firms hold for commercial purposes, and those the federal government holds in the Strategic Petroleum Reserve (SPR) for use during periods of major supply interruption. Weekly data for September 13 indicate total U.S. commercial inventories were equivalent to 24 days of current U.S. refinery crude oil inputs, with the SPR holding additional volumes equal to slightly more than 37 additional days of current refinery inputs, for a total of 62 days. The supply coverage provided by oil inventories can also be measured by days of net crude oil imports (imports minus exports). By this metric, as of June 2019 the United States could meet its net import needs by drawing down the SPR for 162 days. The Energy Policy and Conservation Act states the President may make the decision to withdraw crude oil from the SPR should they find that there is a severe petroleum supply disruption. The SPR has been used in this capacity three times since its creation: first, in 1991 at the beginning of Operation Desert Storm; second, in the wake of Hurricane Katrina in September 2005; and third, in June 2011 to help offset crude oil supply disruptions in Libya.

Although U.S. imports of crude oil from Saudi Arabia have declined during the past three years—and recently hit a four-week average record low of 380,000 b/d in the week ending September 6—the United States still imports about 7 million b/d of crude oil (Figure 4). As a result, a tighter global crude oil market and increased global crude oil prices will ultimately increase the price of crude oil and transportation fuels in the United States.

Figure 4. U.S. crude oil imports (four-week average)

Crude oil prices are the largest determinant of the retail price for gasoline, the most widely consumed transportation fuel in the United States. In general, because gasoline taxes and retail distribution costs are generally stable, movements in U.S. gasoline prices are primarily the result of changes in crude oil prices and wholesale margins. Each dollar per barrel of sustained price change in crude oil translates to an average change of about 2.4 cents/gal in petroleum product prices. About 50% of a crude oil price change passes through to retail gasoline prices within two weeks and 80% within four weeks. However, this price pass-through tends to be more rapid when crude oil prices increase than when they decrease. Brent crude oil prices are more relevant than WTI prices in determining U.S. retail gasoline prices.

EIA is closely monitoring the developments related to the oil supply disruption in Saudi Arabia and the effects that they have on oil markets. EIA’s findings will be reflected in the October STEO, which is scheduled for release on October 8.

U.S. average regular gasoline and diesel prices increase

The U.S. average regular gasoline retail price rose less than 1 cent from the previous week to remain at $2.55 per gallon on September 16, 29 cents lower than the same time last year. The Rocky Mountain and Midwest prices each rose 2 cents to $2.65 per gallon and $2.46 per gallon, respectively. The East Coast price fell nearly 1 cent to $2.45 per gallon, and the Gulf Coast price fell less than 1 cent to $2.23 per gallon. The West Coast price remained unchanged at $3.25 per gallon.

The U.S. average diesel fuel price rose nearly 2 cents to $2.99 per gallon on September 16, 28 cents lower than a year ago. The West Coast and Rocky Mountain prices each rose nearly 3 cents to $3.57 per gallon and $2.96 per gallon respectively, the Midwest and Gulf Coast prices each rose nearly 2 cents to $2.88 per gallon and $2.76 per gallon, respectively, and the East Coast price rose nearly 1 cent to $3.00 per gallon.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 2.9 million barrels last week to 100.7 million barrels as of September 13, 2019, 14.3 million barrels (16.6%) greater than the five-year (2014-18) average inventory levels for this time of year. Gulf Coast inventories increased by 1.2 million barrels, and East Coast and Midwest inventories each increased by 0.9 million barrels. Rocky Mountain/West Coast inventories decreased slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 4.1% of total propane/propylene inventories.

Brent crude oil exports imports inventories stocks prices Saudi Arabia SPR (Strategic Petroleum Reserve) WTI
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Suriname’s Mega Discovery

It was just over five years ago that ExxonMobil discovered first oil in Guyana, transforming the sleepy South American country into the world’s upstream hotspot in just half a decade. The strike rate there has been amazing – 18 discoveries out of 20 well campaigns, and more seem to coming as new discovery efforts get underway. This made Guyana the envy of its neighbours. And why not? The Guyanese economy is projected to grow at 86% y-o-y in 2020, despite the Covid-19 pandemic, as first commercial oil from the Liza field hit the market.

Just over the Guyana border, Suriname, a former Dutch colony had all the more reason to be envious. Unlike Guyana, Suriname has an established upstream industry. Managed by the state oil firm Staastsolie, the volumes are paltry: the onshore Calcutta and Tamabredjo field collectively produce at a current rate of 17,000 b/d. Guyana’s Liza field alone is 15 times larger than Suriname’s total crude output. But the Guyanese miracle always did herald some hope that some of that golden dust could blow Suriname’s way, not least because the giant offshore discoveries in the Staebroek block were just across the maritime border.

In January 2020, this bet proved right. US independent Apache announced it had made a ‘significant oil discovery’ at the Maka-Central 1 well, the first suggestion that the Cretaceous oil formation in Guyana extended southeast to Suriname. Two more discoveries were announced by Apache in quick succession, Sapakara West and, just this week, Kwaskwasi. All three are located in the 1.4 million acre offshore Block 58, which was originally held entirely by Apache before French supermajor Total bought into a 50% stake just before the Maka Central discovery was announced. Three discoveries in six month is quite a payoff, especially with the Kwaskwasi-1 well delivering the highest net pay and confirming a ‘world-class hydrocarbon resource’. More importantly, initial findings suggest that Kwaskwasi holds oil with API gravities in the 34-43 degree range, the sort of light oil that is perfect for petrochemicals and higher-grade fuels.

With Total scheduled to take over operatorship of the block after a fourth drilling campaign, the partners are eager to extend their streak. The Sam Croft drillship is scheduled to head to Keskesi, the fourth scheduled prospect in Block 58, after operations at Kwaskwasi-1 have concluded, and an additional exploration campaign is already in the plans for 2021.

Total and Apache aren’t the only ones playing in Surinamese waters, though they are the first to hit the payday. Most of the country’s offshore blocks have been apportioned, snapped up by ExxonMobil, Kosmos, Petronas, Tullow and Equinor, and all are hoping to be the next to announce a find. ExxonMobil, with Equinor and Hess Energy, have a good position in Block 59, just next to the Caieteur block in Guyana, while Kosmos is hunting in Block 42, right next to the Canje block in Guyana. However, it is Malaysia’s Petronas that is the next likely candidate. Present in Suriname since 2016, when it drilled the exploratory Roselle-1 well in Block 52, Petronas also has interests in Block 48 and Block 53, and recently completed a farm-out sale with ExxonMobil for 50% of Block 52. Its drilling campaign for the Sloanea-1 well is scheduled to begin in Q4 2020, and will be keenly watched by all in Suriname.

Unlike Guyana that had no state oil company, Suriname has existing national oil infrastructure. Staatsolie currently controls onshore and shallow water areas in the country. However, all wells drill in offshore Block A, B, C and D have turned out dry so far. That leaves Staatsolie in a situation: its own areas are not prolific as discoveries by Total, Apache, Petronas et al. For now, Staatsolie is looking to gain rights to 10-20% of any oil discovery within Suriname, but the framework for this is weak and it must navigate carefully to not antagonise the oil majors that are powering the discoveries in its waters. It will do well to avoid the confrontational attitude that is jeopardising LNG development in Papua New Guinea with ExxonMobil and Total, but Staatsolie does have a claim to Suriname’s oil riches for itself.

For now, it is exhilarating to observe the progress in this previously quiet corner of South America. It is the closest thing to frontier oil exploration in the 21st century, with each new discovery generating more and more excitement. Who would have thought there was so much oil left undiscovered? Guyana has shot into the spotlight, Suriname is starting its own ascent and… who knows… could French Guiana be next?

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August, 01 2020
2019 U.S. coal production falls to its lowest level since 1978

U.S. total annual coal production

Source: U.S. Energy Information Administration, Annual Coal Report

In 2019, U.S. coal production totaled 706 million short tons (MMst), a 7% decrease from the 756 MMst mined in 2018. Last year’s production was the lowest amount of coal produced in the United States since 1978, when a coal miners’ strike halted most of the country’s coal production from December 1977 to March 1978. Weekly coal production estimates from the U.S. Energy Information Administration (EIA) show the United States is on pace for an even larger decline in 2020, falling to production levels comparable with those in the 1960s.

2019 annual coal production by state

2019 annual coal production, top 10 coal-producing states


Source: U.S. Energy Information Administration, Annual Coal Report

Wyoming produces more coal than any other state, representing 39% of U.S. coal production in 2019, at 277 MMst, which is 9% lower than its coal production in 2018. Coal production in West Virginia, the state with the second-highest coal output, fell by a relatively smaller 2% in 2019. West Virginia is a primary producer of metallurgical coal, which saw sustained demand for exports in 2019. Coal production recently stopped in two states, Kansas in 2017 and Arkansas in 2018. Arizona stopped producing coal in the fall of 2019 when the coal-fired Navajo Generating Station and adjacent Kayenta coal mine that supplied it both closed.

EIA estimates weekly coal production using coal railcar loadings. In 2020, weekly coal railcar loadings have been trending much lower than 2019 levels, and most recent year-to-date coal railcar loadings were down 27% compared with 2019.

U.S. weekly railcar loadings

Source: U.S. Energy Information Administration, Weekly Coal Production

The decline of U.S. coal production so far in 2020 reflects less demand for coal internationally and less generation from U.S. coal-fired power plants. U.S. coal exports through May 2020 are 29% lower than during the first five months of 2019. U.S. coal-fired generation fell to a 42-year low in 2019, decreasing nearly 16% from the previous year, and has fallen another 34% through May 2020.

Estimated U.S. coal production through mid-July 2020 is 27% lower than the average annual 2019 output, and EIA expects these reductions in production to persist during the remainder of the year. In the latest Short-Term Energy Outlook (STEO), EIA forecasts a 29% decline in U.S. coal production in 2020.

EIA forecasts that U.S. coal production will increase by 7% in 2021, when rising natural gas prices may cause some coal-fired electric power plants to become more economical to dispatch. Much of EIA’s projected recovery in coal production is in the western United States.

Principal contributor: Rosalyn Berry

July, 29 2020
Key Upstream Positive Developments Since April 2020

Amid the unprecedented upheaval that has taken its toll on the world and, in particular the energy industry in the first half of this year, life goes on. Despite shut-ins, weak prices, huge impairments, gloomy forecasts and business challenges, life still goes on. Rigs are still running, exploration is still being conducted and projects are still being approved. The oil and gas world has weathered a huge storm, but that has not stopped it from focusing on necessary work that is vital for the future of the industry itself and the global economy. We have summarised a list of key upstream announcements and developments since April.

One of the major headlines that came out over the past three months was news that Total’s giant LNG in Mozambique has secured as much as US$16 billion in funds from various financial institutions. This is the single largest foreign direct investment project in Africa ever, matching the total current GDP of Mozambique. The speed at which Total completed financing for the US$23 billion project (which taps in the gigantic Golfinho and Atum natural gas fields) is quite remarkable, when the ExxonMobil-led Rovuma LNG next door is facing delays. In fact, the funding raised US$600 million than expected, representing the faith that the 13.1 million ton per annum project, potentially expandable to 43 mtpa, will pay off in the long run. For Total, this will be a hedge, given that its LNG efforts in Papua New Guinea are currently still stymied by a showdown against the country’s new government.

Chevron also had some major news to publish. After failing to acquire Anadarko in 2019 in a dramatic storyline against Occidental Petroleum, the US supermajor has swooped in to acquire US independent Noble Energy for some US$5 billion. The acquisition neatly replaces what the original Anadarko purchase was supposed to achieve – expand Chevron’s presence in the prolific US onshore shale basins, with Noble’s 92,000 acres in the Permian noted as being ‘largely contiguous and adjacent’ to Chevron’s current assets. Noble will also bring with it established positions in the Eagle Ford basin, significant US midstream assets and upstream assets in Israel and Equatorial Guinea, swelling Chevron’s proven oil and gas reserves by 18%. For that amount of potential, the price is a steal. With smaller shale players under pressure, expect more acquisitions of this sort to be announced by deep-pocketed bargain hunters.

Chevron wasn’t the only one to make acquisitions. ConocoPhillips splashed out US$375 million to take up land in Western Canada’s liquids-rich Montney formation, taking the Inga-Fireweed asset from Kelt Exploration. Trident Energy completed its purchase of 10 concessions in the offshore Pampo and Enchova clusters in Brazil from Petrobras. And trader Vitol announced a rara avis, a new US upstream venture called Vencer Energy, focusing on acquiring and operating mature assets in the US Lower 48 region from its base in Houston.

New discoveries have also been coming at a regular speed. Despite divesting assets, Petrobras announced two new discoveries in the offshore Buzios and Albacora pre-salt fields, with reserves of ‘excellent quality’. Eni continues its winning run in Egypt with the new Bashrush natural gas discovery in the Mediterranean Sea, while MOL made its lucky 13th discovery in Pakistan with the Mamikhel South-1 well (the tenth in the TAL Block alone) that revealed ‘significant gas and condensate reserves’. ExxonMobil has restarted two of its four drillships in Guyana and Petronas has handed out contracts in Suriname, so more discoveries are due from that part of the Caribbean. Neptune Energy hit oil at the Dugong well in the Norwegian North Sea, and China’s CNOOC announced a ‘significant discovery’ at the Huizhou 26-6 well in the Pearl River Mouth Basin – the first mid-to-large sized oil and gas field in the area.

CNOOC will be hoping the Huizhou discovery will continue its streak of recent discoveries, boosting domestic Chinese upstream output. Its Luda 21-2/16-3 asset, in the Bohai Sea’s Liaodong Bay, has just started up production, reaching a peak of 25,600 b/d in 2022. Sinopec is also marshalling resources, announcing a US$770 million plan to develop the Dingbei gas prospect in Ningxia and its 230 bcm of natural gas.

Medco reported first gas from the Meliwis field off East Java in Indonesia from an unmanned platform, while the National Iranian Oil Co shrugged off a domestic economic crisis to partner with Persia Oil and Gas Industry Development Co for US$463 million to re-develop the Yaran field in the Khuzestan Province, raising output by 40 million barrels over 10 years. And then in frozen Siberia, where Novatek is speeding ahead with LNG, Gazprom Neft and Shell have agreed to collaborate on developing the Leskinsky and Pukhutsyayakhshy blocks in the Gydan Peninsula: an unusual display of cooperation between a Russian state firm and a Western supermajor.

This is not an exhaustive list of recent developments in the upstream oil and gas corner of the universe. They are the most notable, but there are other signs that the thaw is coming and the industry can recover and begin to grow again. Covid-19 may be something that we must all learn to live with going forward, but life will always go on, and this too shall pass.

Market Outlook:

  • Crude price trading range: Brent – US$42-44/b, WTI – US$40-42/b
  • Global crude oil price markers remain stuck in the lower US$40/b area, as concerns of demand linger given the accelerating rate of Covid-19 in the Americas
  • News that OPEC+ was looking for a gradual phasing into the new supply quota level provides some support on the supply side, while key developments in potential Covid-19 vaccines indicate that first availability could be as early as September
  • A massive stimulus package agreed by the EU and positive messaging of recovery in Asia after two quarters of bad economic data also offer hope that growth could resume soon, though global trends are likely to be uneven given the situation in the Americas

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In this time of COVID-19, we have had to relook at the way we approach workplace learning. We understand that businesses can’t afford to push the pause button on capability building, as employee safety comes in first and mistakes can be very costly. That’s why we have put together a series of Virtual Instructor Led Training or VILT to ensure that there is no disruption to your workplace learning and progression.

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July, 26 2020