NrgEdge Editor

Sharing content and articles for users
Last Updated: November 29, 2019
1 view
Business Trends
image

Market Watch  

Headline crude prices for the week beginning 25 November 2019 – Brent: US$63/b; WTI: US$58/b

  • Oil prices have been edging upwards recently, but largely staying rangebound as data failed to overcome sentiment and the spectre of the US-China trade war
  • Trade negotiations between the USA and China got a bit more complicated with the US Congress passing a bill supported rights and autonomy in Hong Kong; signed into law by President Donald Trump, the move could jeopardise the probability of a comprehensive trade deal emerging anytime soon
  • Ahead of OPEC’s bi-annual meeting in Vienna next week, the stage has been set for a contentious round; the current OPEC+ supply pact will expire in March 2020, and a decision to either end, extend or expand the deal must be made at the meeting that begins on December 5
  • Eyes will be on Russia, which has failed to adhere to its share of the output cuts as Energy Minister Alexander Novak said that the country was ‘trying to reach the planned level’ but faced challenges in weather and geography
  • Against the backdrop, the US EIA reports that output from the seven major onshore shale formations is expected to rise by 49,000 b/d to a record 9.1 mmb/d, with the Permian hitting 4.73 mmb/d, even as the active rig count drops
  • But in California, the state has halted permits for high-pressure steam flooding following leaks at Chevron’s Cymric field, hampering the industry
  • In the UK, politicking for the upcoming general elections – aimed at providing clarity on Brexit – has led the Labour party to propose a windfall tax on all oil companies and a ‘permanent ban’ on fracking, which could hasten the decline in the UK oil and gas industry
  • The chronic declines in the US active rig count continue, with the total falling again as 3 oil rigs stopped work, bringing the active count down to 803 – or 276 fewer sites year-on-year
  • Nothing but rangebound trading is expected for crude prices, given the number of factors that still up in the air – the outcome of the OPEC December meeting and the continued ping-pong situation in the US-China trade war; Brent and WTI will, therefore, stay trading at US$60-63/b and US$56-59/b respectively


Headlines of the week

Upstream

  • Senegal’s national oil company – PETROSEN – will be launching the country’s first offshore licensing round in January 2020, with 10 exploration blocks in the prolific MSGBC basin on offer to be awarded in July 2020
  • ConocoPhillips has announced a plan to pull back from an over-dependence on US shale, focusing on morphing into a low-growth, high-cash generating company instead of an aggressive shale exploiter to preserve shareholder value
  • Shell will begin drilling its first well in Mexico – the Chibu-1EXP deepwater well within the offshore Campeche basin - by end-2020, as supermajor interest in Mexican upstream begins to translate into concrete E&P activity
  • Strikes at Canadian National Railways has halted shipments of crude-by-rail from Alberta, as the rail company prioritised movement of food goods
  • The heady optimism of Guyanese oil finds has been tempered recently, with ExxonMobil and Hess announcing that oil at the Hammerhead well is heavier than expected, a week after Tullow said the same of its crudes

Midstream/Downstream

  • US refiner HollyFrontier will be building a new biodiesel plant in New Mexico as it attempts to reduce costs by adapting to new US mandates on biofuel that require refiners to blend increasing volumes of bio-feedstocks into gasoil
  • Sinopec is aiming to launch its new 200,000 b/d refinery in Zhanjiang – fed by Kuwaiti crude – in 2Q2020, the third greenfield refinery that will enter operation in China in space of 2 years
  • India has officially launched its largest privatisation drive in a decade, offering the government’s entire stake in BPCL – among other big-ticket items – to private investors, with interest coming from Saudi Aramco and ADNOC
  • As Indonesia makes a push to introduce a new B30 biodiesel mandate nationwide over 2020, the move could display up to 165,000 b/d in volumes away from gasoil towards palm oil feedstock

Natural Gas/LNG

  • Qatar is planning to boost its LNG production capacity to 126 million tpa by 2027 – up by 64% from a current 77 million tons – as it focuses on expanding development in the massive North Field, with work on two new LNG trains with a combined capacity of 16 million tpa having recently started
  • BP has struck new gas in Trinidad & Tobago, with the Ginger exploration well yielding gas flows, extending BP’s success streak in the island nation that includes the recent Savannah and Macademia discoveries
  • The US FERC has approved four new LNG export projects – Exelon Corp’s Annova LNG, NextDecade Corp’s Rio Grande LNG and Texas LNG projects, as well Cheniere’s expansion at Corpus Christi – which would roughly double current US LNG export capacity just as the global market is hitting a glut
  • Novatek is pushing the Russian government to support and finance an LNG transhipment terminal at the Kamchatka Peninsula with capacity for 20 million million tpa to support Novatek’s expanded production in the area
  • After suffering from a severe shortage, Australia’s east coast is now facing the opposite problem, with the current oversupply in global LNG creating a low gas price environment, but supply deficits could kick in again after 2023
  • SKK Migas, Indonesia’s upstream regulator, has set a target to the upstream industry to increase natural gas production by a third to 1 mmboe/d in 2030 from a current 750,000 boe/d, targeting potential from the Masela Block

Oil Oil and gas news oil and gas industry LNG oil and gas companies News weekly update market watch market trends latest oil and gas trennds
3
2 0

Something interesting to share?
Join NrgEdge and create your own NrgBuzz today

Latest NrgBuzz

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

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.

Find courses available for Virtual Instructor Led Training through latest video conferencing technology.

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