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Crude oil prices have fallen significantly since the beginning of 2020, largely driven by the economic contraction caused by the 2019 novel coronavirus disease (COVID19) and a sudden increase in crude oil supply following the suspension of agreed production cuts among the Organization of the Petroleum Exporting Countries (OPEC) and partner countries. With falling demand and increasing supply, the front-month price of the U.S. benchmark crude oil West Texas Intermediate (WTI) fell from a year-to-date high closing price of $63.27 per barrel (b) on January 6 to a year-to-date low of $20.37/b on March 18 (Figure 1), the lowest nominal crude oil price since February 2002.
WTI crude oil prices have also fallen significantly along the futures curve, which charts monthly price settlements for WTI crude oil delivery over the next several years. For example, the WTI price for December 2020 delivery declined from $56.90/b on January 2, 2020, to $32.21/b as of March 24. In addition to the sharp price decline, the shape of the futures curve has shifted from backwardation—when near-term futures prices are higher than longer-dated ones—to contango, when near-term futures prices are lower than longer-dated ones. The WTI 1st-13th spread (the difference between the WTI price in the nearest month and the price for WTI 13 months away) settled at -$10.34/b on March 18, the lowest since February 2016, exhibiting high contango. The shift from backwardation to contango reflects the significant increase in petroleum inventories. In its March 2020 Short-Term Energy Outlook (STEO), released on March 11, 2020, the U.S. Energy Information Administration (EIA) forecast that Organization for Economic Cooperation and Development (OECD) commercial petroleum inventories will rise to 2.9 billion barrels in March, an increase of 20 million barrels over the previous month and 68 million barrels over March 2019 (Figure 2). Since the release of the March STEO, changes in various oil market and macroeconomic indicators suggest that inventory builds are likely to be even greater than EIA’s March forecast.
Significant price volatility has accompanied both price declines and price increases. Since 1999, 69% of the time, daily WTI crude oil prices increased or decreased by less than 2% relative to the previous trading day. Daily oil price changes during March 2020 have exceeded 2% 13 times (76% of the month’s traded days) as of March 24. For example, the 10.1% decline on March 6 after the OPEC meeting was larger than 99.8% of the daily percentage price decreases since 1999. The 24.6% decline on March 9 and the 24.4% decline on March 18 were the largest and second largest percent declines, respectively, since at least 1999 (Figure 3).
On March 10, a series of government announcements indicated that emergency fiscal and monetary policy were likely to be forthcoming in various countries, which contributed to a 10.4% increase in the WTI price, the 12th-largest daily increase since 1999. During other highly volatile time periods, such as the 2008 financial crisis, both large price increases and decreases occurred in quick succession. During the 2008 financial crisis, the largest single-day increase—a 17.8% rise on September 22, 2008—was followed the next day by the largest single-day decrease, a 12.0% fall on September 23, 2008.
Market price volatility during the first quarter of 2020 has not been limited to oil markets (Figure 4). The recent volatility in oil markets has also coincided with increased volatility in equity markets because the products refined from crude oil are used in many parts of the economy and because the COVID-19-related economic slowdown affects a broad array of economic activities. This can be measured through implied volatility—an estimate of a security’s expected range of near-term price changes—which can be calculated using price movements of financial options and measured by the VIX index for the Standard and Poor’s (S&P) 500 index and the OVX index for WTI prices. Implied volatility for both the S&P 500 index and WTI are higher than the levels seen during the 2008 financial crisis, which peaked on November 20, 2008, at 80.9 and on December 11, 2008, at 100.4, respectively, compared with 61.7 for the VIX and 170.9 for the OVX as of March 24.
Comparing implied volatility for the S&P 500 index with WTI’s suggests that although recent volatility is not limited to oil markets, oil markets are likely more volatile than equity markets at this point. The oil market’s relative volatility is not, however, in and of itself unusual. Oil markets are almost always more volatile than equity markets because crude oil demand is price inelastic—whereby price changes have relatively little effect on the quantity of crude oil demanded—and because of the relative diversity of the companies constituting the S&P 500 index. But recent oil market volatility is still historically high, even in comparison to the volatility of the larger equity market. As denoted by the red line in the bottom of Figure 4, the difference between the OVX and VIX reached an all-time high of 124.1 on March 23, compared with an average difference of 16.8 between May 2007 (the date the OVX was launched) and March 24, 2020.
Markets currently appear to expect continued and increasing market volatility, and, by extension, increasing uncertainty in the pricing of crude oil. Oil’s current level of implied volatility—a forward-looking measure for the next 30 days—is also high relative to its historical, or realized, volatility. Historical volatility can influence the market’s expectations for future price uncertainty, which contributes to higher implied volatility. Some of this difference is a structural part of the market, and implied volatility typically exceeds historical volatility as sellers of options demand a volatility risk premium to compensate them for the risk of holding a volatile security. But as the yellow line in Figure 4 shows, the current implied volatility of WTI prices is still higher than normal. The difference between implied and historical volatility reached an all-time high of 44.7 on March 20, compared with an average difference of 2.3 between 2007 and March 2020. This trend could suggest that options (prices for which increase with volatility) are relatively expensive and, by extension, that demand for financial instruments to limit oil price exposure are relatively elevated.
Increased price correlation among several asset classes also suggests that similar economic factors are driving prices in a variety of markets. For example, both the correlation between changes in the price of WTI and changes in the S&P 500 and the correlation between WTI and other non-energy commodities (as measured by the S&P Commodity Index (GSCI)) increased significantly in March. Typically, when correlations between WTI and other asset classes increase, it suggests that expectations of future economic growth—rather than issues specific to crude oil markets— tend to be the primary drivers of price formation. In this case, price declines for oil, equities, and non-energy commodities all indicate that concerns over global economic growth are likely the primary force driving price formation (Figure 5).
U.S. average regular gasoline and diesel prices fall
The U.S. average regular gasoline retail price fell nearly 13 cents from the previous week to $2.12 per gallon on March 23, 50 cents lower than a year ago. The Midwest price fell more than 16 cents to $1.87 per gallon, the West Coast price fell nearly 15 cents to $2.88 per gallon, the East Coast and Gulf Coast prices each fell nearly 11 cents to $2.08 per gallon and $1.86 per gallon, respectively, and the Rocky Mountain price declined more than 8 cents to $2.24 per gallon.
The U.S. average diesel fuel price fell more than 7 cents from the previous week to $2.66 per gallon on March 23, 42 cents lower than a year ago. The Midwest price fell more than 9 cents to $2.50 per gallon, the West Coast price fell more than 7 cents to $3.25 per gallon, the East Coast and Gulf Coast prices each fell nearly 7 cents to $2.72 per gallon and $2.44 per gallon, respectively, and the Rocky Mountain price fell more than 6 cents to $2.68 per gallon.
Propane/propylene inventories decline
U.S. propane/propylene stocks decreased by 1.8 million barrels last week to 64.9 million barrels as of March 20, 2020, 15.5 million barrels (31.3%) greater than the five-year (2015-19) average inventory levels for this same time of year. Gulf Coast inventories decreased by 1.3 million barrels, East Coast inventories decreased by 0.3 million barrels, and Rocky Mountain/West Coast inventories decrease by 0.2 million barrels. Midwest inventories increased by 0.1 million barrels. Propylene non-fuel-use inventories represented 8.5% of total propane/propylene inventories.
Residential heating fuel prices decrease
As of March 23, 2020, residential heating oil prices averaged $2.45 per gallon, almost 15 cents per gallon below last week’s price and nearly 77 cents per gallon lower than last year’s price at this time. Wholesale heating oil prices averaged more than $1.11 per gallon, almost 14 cents per gallon below last week’s price and 98 cents per gallon lower than a year ago.
Residential propane prices averaged more than $1.91 per gallon, nearly 2 cents per gallon below last week’s price and almost 49 cents per gallon below last year’s price. Wholesale propane prices averaged more than $0.42 per gallon, more than 7 cents per gallon lower than last week’s price and almost 36 cents per gallon below last year’s price.
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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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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.
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.
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
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:
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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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