NrgEdge Staff

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Last Updated: February 1, 2017
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Last week in world oil:

Prices

-       With news that US drilling was rising at its fastest pace in two years and Asian buyers turning to avenues such as North Sea oil counteracting the (thus-far) effective OPEC supply cut, crude prices have not budged much from their positions around US$55/b for Brent and US$52/b for WTI.

Upstream & Midstream

-       One of Donald Trump’s first executive orders as President of the USA has been a chaotic ban on citizens of seven Muslim countries entering the USA. This has prompted tit-for-tat measures by Iraq and Iran, moving to ban entry to Americans to their countries. For Iran, this could effectively freeze out American firms from participating in the revitalisation of Iran’s oil and gas industry, ceding ground to European and Chinese players. For Iraq, this complicates the matters as US army personnel as vital to Iraq’s fight against ISIS and poses a question mark on American participation (particularly ExxonMobil’s) in the Iraqi energy industry.

-       The Keystone XL and Dakota Access oil pipelines are back in business, with President Donald Trump signalling support but demanding renegotiation to ‘secure a better deal for the US’. Some of the new caveats include the use of US-made products – difficult to achieve as the US steel industry isn’t up to par – and reducing environmental reviews.

-       Shell is preparing a sale of its North Sea oil and gas assets to area specialist Chrysaor for US$3 billion, as it continues its divestment drive to pay for its acquisition of the BG Group. The package of assets will be a mix of older fields, new developments and infrastructure, which could inject new blood into an area in steady decline.

-       Some 15 oil rigs started up last week, joined by 3 gas rigs, to raise the number of operational oil and gas rigs in the US to 712. This is the monthly fastest pace of additions in over three years, as US drillers capitalise on stronger oil prices as well as indications by the new Trump administration that they will support expansion in domestic upstream and reduce restrictions.

-       Despite a USD415 million net income reported in Q4 2016, Chevron posted a USD497 million loss for 2016 as the slump in refining earnings outweighed recovering oil prices in H2 2016. The company replaced 95% of its production with new oil and gas reserves mostly from Kazakhstan, the US, and Australia

-       The oilfield services company, Baker Hughes announced a USD417 million net loss on revenue of USD2.41 billion for Q4 2016. For the same quarter last year, the company lost more than USD1 billion on revenue of USD3.39 billion

-       In 2012, Turkey referred Iran to the International Court of Arbitration for overpricing gas sales to Turkey between 2011 and 2015. The court ruled in favour of Turkey in February 2016, and as a result, Iran will pay Turkey USD1.9 billion in compensation and discount gas price by 13.5%.

Downstream

-       With BP’s annual forecast calling for energy demand to grow by a third through 2035, driven by demand in Asia and Africa, global players have turned their attention to African infrastructure. In Nigeria, General Electric has proposed a plan to revamp the country’s three ailing refineries, potentially creating a consortium with NNPC, which is in the process of being privatised. Italy’s Eni, as well, has announced plans to deepen Nigerian participation, both upstream and downstream.

-       An explosion at the Tema refinery, the only processing site in Ghana, has caused the entire facility to be shut. The blast came upon the installation of a crude oil heating unit, destroying the new furnace; the plant will be restarted after reconfiguration but operating capacity will drop by a third.

-       In more Shell divestment news, the supermajor is selling its 50% stake in petrochemical player Saudi Petrochemical (SADAF) to Saudi Basic Industries (SABIC) for US$820 million, the third Saudi Arabia-Shell ventures to be killed since 2014, after a natural gas ventures and US-based Motiva. Debt paring following the BG acquisition is the motive.

 

Last week in Asian oil: 

Upstream & Midstream

-       India has signed a deal with ADNOC to fill half of its new Mangalore crude oil storage facility. Up to 6 million barrels of UAE crude, mainly the Murban grade, will be stored at Mangalore, with the other half of storage already occupied by Iranian crude. It is a big step towards achieving India’s goal of increasing energy security through strategic reserves, but at only 10 days of oil demand, it is woefully behind other major oil consumers, with China aiming for 90 days and Japan having 160 days.

-       The governments of Australia and Timor-Leste have given themselves a deadline of September 2017 to agree on a permanent maritime border between the two nations, settling once and for all the ownership of the Greater Sunrise field, with the results likely to benefit Timor-Leste.

 Downstream & Shipping

-       Despite Saudi Aramco’s decision to pull out of the massive RAPID refining and petrochemical hub in Johor, Malaysia’s Petronas has reaffirmed its plans. It remains on track internally for a 2019 start-up, though the departure of Saudi Aramco may force Petronas to secure another crude-rich partner to support the US$27 billion, 300 kb/d refinery. Iran is a possibility, with Petronas unlikely to go ahead alone due to its capex cuts.

Natural Gas & LNG

-       Already facing cost spirals that have ballooned to over US$35 billion, Australia’s massive Ichthys LNG export project has been dealt another blow as engineering contractor CIMIC pulled out of the facility’s associated power plant. With the power plant – which would supply the site with electricity – touted at 89% completion, this suggest major disagreement within the consortium, which will only add to costs and delays, though Ichthys will still go ahead. It is not alone though; Chevron’s Gorgon and Shell’s floating Prelude projects are also facing major budget and timeline problems, delaying Australia’s gigantic LNG ramp up.

-       Commercial operations have officially started at the Petronas LNG ninth liquefaction train in Bintulu, Sarawak. The site is a joint venture between Petronas and Japan’s JX Nippon Oil & Energy Corp, and the ninth train brings the total capacity of the Bintulu LNG plant to 30 million tons per year, much of which is destined to go north to Japan.

Corporate

-       PTTEP, the upstream arm of Thailand’s PTT Group has returned to the black, posting a net profit of US$372 million for 2016 after a loss of US$854 million in 2015, attributed to strong operational performances and cost control. Back on stronger financial footing, PTTEP plans to spend US$4 billion to investment, which will mainly focus on securing natural gas and LNG supplies to offset the decline in Thai gas production.

 

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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