New base energy news 29 june 2020 issue no. 1351 compressed

Copyright © 2020 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,
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NewBase Energy News 28 June 2020 - Issue No. 1351 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
U.A.E: Mubadala delivers bid for Petrobras' refinery in Brazil
Reuters Carolina Mandl, Sabrina Valle
Abu Dhabi’s Mubadala Investment Company placed a binding offer for Petroleo Brasileiro SA’s
refinery in the northeastern Brazilian state of Bahia on Thursday, two people with knowledge of the
matter said on Friday.
The 330,000 barrel-a-day refinery, known as RLAM, is the first of a group of eight such units the
state-controlled oil producer plans to sell to cut debt and open one of the world’s largest fuel markets
to private investors. It is still unclear whether other players, such as China’s Sinopec and Indian
conglomerate Essar Group, also made offers. Petrobras and Mubadala declined to comment.
About Petrobras Refining
Currently have 13 refineries, spread nationwide, and a shale processing unit in Paraná. refining
park produces several oil products per day, such as diesel, gasoline, naphtha, jet fuel, liquefied
petroleum gas, and lubricants, among other substances used as feedstock for many other products.
Over the last few years, have invested in revamping our refineries to improve product quality,
increase productivity, and reduce our operations’ environmental impact. All this has always been
based on the best Brazilian and international industry practices and principles of safety,
environment, and health that guide our actions.
Oman refineries cut fuel output as pandemic hits demand
Oman Observer - Conrad Prabhu
State-owned OQ (formerly Oman Oil and Orpic Group), which owns and operates the Sultanate’s
two principal refineries, reported a sharp decline in the production of motor fuels during the first five
months of this year, reflecting a dramatic slump in demand as many people remained homebound
in line with lockdown measures imposed by authorities to contain the spread of the coronavirus.

Production of the M91 grade of gasoline plummeted a hefty 30 per cent to 4.409 million barrels for
the January – May period of this year, down from 6.628 million barrels for the corresponding period
of 2019. The output of the premium M95 grade fell 17 per cent to 4.549 million barrels this year,
down from 5.490 million during the first five months of 2019.
Aviation fuel production slid 32 per cent to 4.150 million barrels this year versus 6.119 million barrels
for the same period in 2019. Output of LPG (cooking gas) declined 17 per cent to 2.677 million
barrels this year, from 3.209 million barrels during Jan – May 2019. The only bright spot was gas
oil (diesel), production of which climbed 19 per cent to 13.326 million barrels this year, up from
11.170 million barrels last year.
The collapse in demand for motor fuels, as well as jet fuel, forced the temporary shutdown of OQ’s
Mina al Fahal refinery in Muscat, according to officials of the Ministry of Oil and Gas. With pandemic
containment measures, coupled with work-from-home practices, coming into force in March,
vehicular traffic was reduced to a minimum on the Sultanate’s roads.
According to figures released by the National Centre for Statistics and Information (NCSI), domestic
sales of M91 gasoline plunged 28 per cent during the first five months of the year. The decline was
equally significant for other refined petroleum products: M95 (16 per cent), gas oil (14 per cent), and
aviation fuel (44 per cent).
Domestic sales of cooking gas, in contrast, climbed 12 per cent during this period, reflecting an
uptick in home cooking as families and other people were largely confined indoors during the
lockdown.
U.S. refinery capacity sets new record as of January 1, 2020
Source: U.S. Energy Information Administration, Refinery Capacity Report
U.S. operable atmospheric crude oil distillation capacity increased 0.9% during 2019, reaching a
record of 19.0 million barrels per calendar day (b/cd), up 0.2 million b/cd from the previous record
of 18.8 million b/cd the year before.

According to the U.S. Energy Information Administration’s (EIA) annual Refinery Capacity Report,
U.S. operable crude oil distillation unit (CDU) capacity has increased slightly in seven of the past
eight years.
EIA measures refinery capacity in two ways: barrels per calendar day and barrels per stream day
(b/sd). Calendar-day capacity is the operator’s estimate of the input that a distillation unit can
process in a 24-hour period under usual operating conditions, recognizing the effects of both
planned and unplanned maintenance.
Stream-day capacity reflects the maximum number of barrels of input that a distillation facility can
process within a 24-hour period when running at full capacity under optimal crude oil and product
slate conditions with no allowance for downtime. Stream-day capacity is typically about 6% higher
than calendar-day capacity.
The number of operable refineries in the United States (excluding U.S. territories), which includes
both idle and operating refineries, started 2019 at a total of 135. One refinery shut down in 2019:
Continental Refining Company LLC’s 5,500 b/cd refinery in Somerset, Kentucky, which had been
inactive since March 2018. However, Flint Hills Resources split out its reporting to EIA of the Corpus
Christi East and West plants, bringing EIA’s calculation of the number of operable U.S. refineries
back to 135.
The 335,000 b/cd Philadelphia Energy Solutions refinery remained in EIA’s refinery count as of
January 1, but it has not operated since shortly after a fire in June 2019 damaged part of the refinery
complex; a sale of the refinery is pending.
As the United States has increased crude oil production over the past decade, the average density
of U.S. crude oil has become lighter. Because U.S. refineries imported less of the crude oil they
processed and replaced imports with domestically produced crude oil, the average API gravity—a

measure of a crude oil’s density where higher numbers mean lower density—of crude oil inputs to
refineries increased.
For example, the U.S. Gulf Coast, which is home to about half of U.S. refining capacity, used
imported crude oil for only 28% of its crude oil inputs to refineries during 2019, down from 69% in
2010.
Source: U.S. Energy Information Administration, Petroleum Supply Monthly
Note: Difference between total crude oil sources and gross inputs includes supply from inventory
and refinery inputs of other oils.
U.S. refineries have adapted to this changing crude oil slate by slightly increasing their yields of
petroleum products that are derived from lighter crude oil, such as jet fuel, gasoline, and distillate.
They have also increased their use of downstream refinery units, which are used to process the
products coming from the atmospheric crude distillation unit into ultra-low sulfur diesel and gasoline
as well as other products. These lighter products often have higher refining margins, a measure that
represents the difference between the prices of petroleum products and crude oil.
EIA’s updated Refinery Capacity Report also includes information on capacity expansions planned
for the rest of 2020. Based on information reported to EIA in the most recent update, U.S. refining
capacity will not expand significantly this year.
Pakistan: petrol price by nearly Rs26 citing 'global rise in prices'
https://www.dawn.com
The government on Friday increased the prices of all petroleum products by up to nearly Rs26 to
share the impact of rising international prices with the consumers. The price of petrol (motor spirit)
has been raised by a whopping Rs25.58 to Rs100.10 per litre today from the existing Rs74.52, an
increase of 25.6 per cent, according to a Finance Division press release.

The price of high-speed diesel (HSD) has been hiked to Rs101.46 per litre from the current price of
Rs80.15, a jump of Rs21.31. The new price of kerosene oil (SKO) will be Rs59.06, a rise of Rs23.50
over the existing Rs35.56.
Meanwhile, the price of light diesel oil (LDO) has been pushed up by Rs17.84 to Rs55.98 from the
current Rs38.14. The decision to revise the prices of petroleum products upwards was taken "in
view of the rising oil prices trend in the global market", the brief statement issued by the Finance
Division said.
The new prices are effective from June 26 (today).
The announcement of the fuel prices hike comes unexpectedly as the prices revised last month
were to remain in effect until June 30.
The new prices are usually announced on the last day of a month and usually come into effect after
12am for the upcoming month. In contrast to this practice, the revised prices were announced today
on the same day they went into effect, taking many consumers by surprise.
Last month, the prices of all petroleum products except high-speed diesel had been reduced to
partially pass on the impact of massive international price reduction to the masses.
However, Opec, Russia and allies had earlier this month agreed to extend record oil production cuts
until the end of July, prolonging a deal that has helped crude prices double in the past two months
by withdrawing almost 10pc of global supplies from the market.
Benchmark Brent crude had climbed to a three-month high on June 5 above $42 a barrel, after
diving below $20 in April. Prices still remain about a third lower than at the end of 2019.
The government has already increased the general sales tax (GST) on all petroleum products to a
standard rate of 17pc across the board to generate additional revenues. Until January last year, the
government was charging 0.5pc GST on LDO, 2pc on kerosene, 8pc on petrol and 13pc on HSD.
Besides the 17pc GST, the government has almost quadrupled the rate of petroleum levy on HSD
and petrol to Rs30 per litre — the maximum permissible limit — from Rs8 per litre in January last
year.

Over the last many months, the government had been increasing petroleum levy rates to partially
recoup a major revenue shortfall faced by the FBR. The levy remains in the federal kitty unlike GST
that goes to the divisible pool taxes and thus about 57pc share is grabbed by the provinces.
Petrol and HSD are two major products that generate most of the revenue for the government
because of their massive and yet growing consumption in the country. Average petrol sales are
touching 700,000 tonnes per month against the monthly consumption of around 600,000 tonnes of
diesel. However, the sales of petrol had dropped in recent weeks due to the coronavirus lockdown.
The diesel consumption had also dropped after the lockdown but has since picked up owing to
wheat harvest. The sales of kerosene oil and LDO are generally less than 11,000 and 2000 tonnes
per month.
U.S: Covid to Keep Oil Underground, Forcing Drillers to Change
Bloomberg - Olivia Raimonde + NewBase
Hundreds of billions of barrels of oil stranded by weak demand could accelerate companies’ pivot
to cleaner energy, or threa ten their long-term survival.

BP Plc raised the possibility of stranded oil assets when it announced this month it would take
the biggest writedown on the value of its business in a decade. But it wouldn’t be the only oil
company to leave crude in the ground as the pandemic ravages energy consumption. About 282
billion barrels of undiscovered oil is at risk of being stranded as the virus hastens peak demand,
according to Rystad Energy AS.
“It does start to have significant implications for how some of these companies are making their
investment decisions,” said Jennifer Rowland, an analyst at Edward D. Jones & Co. “Some
companies are starting to make investment decisions today and starting to pivot
either towards shorter-cycle projects like shale or pivot towards renewables.”
BP has already acknowledged that production will decline in the long term, and said whatever is
pumped in 2050 “will have to be de-carbonized.” And French oil major Total SA has already started
its pivot to renewables. Will other companies follow suit?
If they don’t, they may have trouble getting access to the financing they need to keep the drills
running over the next few decades, as lower demand locks their resource in the ground, according
to Rowland.
“There is going to be skepticism about what really is the terminal value of a lot of those assets,” she
said. “It makes their investment proposition that much more of a challenge.”
Shale Fracking Returns, Tapping Huge Glut of Idled Equipment
Shale fracking crews, mired in a glut of idled equipment, are putting some of their pumps back to
work as oil prices rebound.

The number of active U.S. frack crews, which bottomed out at 45 last month, has since jumped to
78 last week, according to industry consultant Primary Vision Inc.
Shale explorers started slashing frack work late last year amid shareholder pressure to spend less,
and they brought activity to a minimum as oil prices plunged below zero in April. In response to
declining demand for their services, pumpers started taking the unprecedented move
of scrapping idle fracking equipment in order to get pricing higher.
While almost 200 frack spreads have been eliminated, the total industry supply still stands at roughly
400 crews, according to research from B Riley FBR Inc. That means roughly 20% of supply is being
put to work today, according to the bank.
“The initial pickup in demand has been stronger than anticipated, but the supply excesses will take
time to purge,” Thomas Curran, an analyst at B Riley FBR, wrote Friday in a note to investors. “The
landscape isn’t just structurally oversupplied, but overcrowded.”
Though there has been a pickup in fracking, the last stage in the development of a shale well,
explorers are still not drilling for new prospects.
The number of rigs drilling for oil in the U.S. has slumped by more than 70% this year, with the count
falling by 1 to 188 this week, Baker Hughes Co. said Friday.
In the Permian Basin of West Texas and New Mexico, the number of rigs was at 131, its lowest in
records going back to 2011.
Shale Oil Recovery Seen Taking Years After Decade of Excess

As oil prices tick up to $40 a barrel following a pandemic-induced plunge, there’s a sense the shale
industry is snapping back to life with Continental Resources Inc., EOG Resources Inc. and Parsley
Energy Inc. all saying they’re restarting closed wells.
But top industry forecasters are painting a far darker picture. The reopenings, they say, will do little
to bring new growth to an industry being increasingly starved of cash by Wall Street after a decade
of excess. Even before the pandemic, investors were demanding companies spend no more than
they earn. Now, that’s become a major barrier to future growth.
Looking out 18 months, U.S. output will still be around 16% below its peak in February, according
to the average of five major forecasters surveyed by Bloomberg. It will probably be at least 2023
before the U.S. again hits its record close to 13 million barrels a day.
“Nothing is going to be in the money,” said Bernadette Johnson, vice president of strategic analytics
at Enverus, a data and research firm. At current crude prices in New York, she added, “very few
new wells are being brought on line.”
Road to Recovery
U.S. oil production faces a long and uncertain path back to its 2020 high
Source: Rystad, International Energy Agency, Genscape, Enverus, IHS Markit

Some 80% of executives surveyed by the Dallas Federal Reserve expect U.S. drilling and fracking
won’t return to pre-Covid levels until at least next year, according to a report published Wednesday.
Another 16% don’t expect the industry to ever return to the same workload again.
Even so, OPEC and its allies should not rest easy.
The shale revolution that made the U.S. the world’s No. 1 producer of oil and gas still retains its
disruptive potential. Forecasters say there’s a high chance that shale could rebound quicker than
expected if futures continue climbing and settle in the $55 to $65 a barrel range for an extended
period of time.
America’s shale industry has defied the doubters for 15 years in terms of sheer volume of oil
produced. In that period, it has more than doubled output, adding about 8 million barrels a day to
global markets. That’s more than if the U.S. had taken over Iraq and Kuwait after President George
W. Bush’s invasion in 2003.
But that achievement came at a huge cost. Shale operators have burned through about $340 billion
over the past 11 years, using borrowed money and equity raised from Wall Street, leaving little left
over for investors. The end result: Energy stocks have fallen this year to less than 3% of the S&P
500 Index in terms of weighting by the companies market capitalization.
As soon as oil prices began tumbling in March, shale producers rapidly slashed everything from drill
rigs to workers and private jets. About 1.75 million barrels a day worth of production was shut in as
producers couldn’t find buyers.
The last month has shown signs of a comeback, but it may be short-lived.
West Texas Intermediate, the U.S. benchmark, has doubled to $40 a barrel since the beginning of
May, providing some relief to the industry’s most indebted names and creating an incentive for
producers including EOG, Continental and Parsley to turn some previously shuttered wells back on.
This is the lowest-cost and easiest supply to resume.
Over the past week, production has ramped up to about 10.8 million barrels a day, a 7% increase
from when output bottomed out from shut-ins, according to Randall Collum Jr, managing director of
upstream analytics at Genscape. Revivals in the Permian, Bakken and Gulf of Mexico have been
particularly strong, he said.
While this may stabilize U.S. production for a few months, it probably won’t be enough to prevent
further declines later in the year, according to IHS Markit and Enverus. That’s because shale’s
explosive growth over the past decade came with a significant handicap: Massive decline rates.
Fracked wells give an initial pop of high production, but drop off by 60% in the first year, meaning
more and more new wells must be drilled to overcome the decline. That requires cash that’s in short
supply. If no new wells are drilled, U.S. production would drop by 35% in just 12 months, about
seven times the rate for the global oil industry, according to Enverus.
Evidence of the negative outlook for producers can be seen in their spending plans, which are down
by almost half to about $54 billion this year. The country now has just 189 active drill rigs, a 72%
drop since March and around the lowest level since 2009, when the shale revolution was in diapers.
Burn Baby, Burn
U.S. shale oil and gas producers have burned through $342 billion since 2010

Source: Deloitte --- *2020 is estimated
Even at $40 a barrel, the outlook for new wells is not good. While costs for the best parts of the
Permian Basin break even below this level, the bulk of U.S. shale does not. In any case, most shale
producers are busy conserving cash to repay their debts.
The big unknown, of course, is the price of oil. If prices rise to $50 a barrel, producers may be
encouraged to start adding rigs again and drilling new wells, according to IHS. At that point, output
could gain quickly, but even Rystad, the most bullish forecaster, doesn’t see the U.S. returning to
the February peak before 2023.
The next level would be the big one. At $60 to $65 a barrel, the U.S. still has the capacity to add 1
million barrels a day for “a very long time,” said Johnson at Enverus.
The big question is how shale producers win back the trust of Wall Street to provide them with the
money to do so. “They have the firepower to grow again but not the financing,” said Raoul LeBlanc,
an analyst at IHS. “That trust will take some time to win back.”
NewBase June 29-2020 Khaled Al Awadi

NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices extend losses as coronavirus spike cools demand hopes
Reuters + Bloomberg + NewBase
Oil prices slid for a second straight session on Monday as coronavirus cases rose in the United
States and other places, leading some countries to resume partial lockdowns that could hurt fuel
demand.
Brent crude LCOc1 dropped 69 cents, or 1.68%, to $40.33 a barrel by 08.41 GMT, while U.S. crude
CLc1 was at $37.89, down 60 cents, or 1.56%.
Brent crude is set to end June with a third consecutive monthly gain after major global producers
extended an unprecedented 9.7 million barrels per day supply cut agreement into July, while oil
demand improved after countries across the globe eased lockdown measures.
“The second wave contagion is alive and well,” Howie Lee, an economist at Singapore’s OCBC
bank, said. “That is capping the bullish sentiment that we’ve seen in the last six to eight weeks.”
Other factors restricting oil prices’ advance at this stage include poor refining margins, high oil
inventories and the resumption of U.S. production, Lee said.

Despite efforts by OPEC+ - the Organization of the Petroleum Exporting Countries (OPEC) and
allies including Russia - to reduce supplies, crude inventories in the United States, the world’s
largest oil producer and consumer, have hit all-time highs.
Even as the number of operating oil and natural gas rigs dropped to a record low last week, higher
oil prices are prompting some producers to resume drilling. “In the next one-two weeks, we should
see an uptick in rig count commensurate with the pick-up in oil production,” OCBC’s Lee said.
Elsewhere, U.S. shale oil pioneer Chesapeake Energy Corp (CHK.N) filed for bankruptcy protection
on Sunday as it bowed to heavy debts and the impact of coronavirus outbreak on energy markets.
The Brent crude price is supported at $39.80 a barrel while WTI’s support level is at $37, OANDA
senior market analyst Jeffrey Halley said, referring to technical charts.
“A daily close below these points will signal that a much deeper correction is upon oil markets,” he
said, adding that a deteriorating COVID-19 picture in the United States would be the most likely
driver of lower prices.
Oil Extends Drop With Virus Milestones Spurring Demand Angst
Oil kept falling after just its second weekly drop since April as coronavirus infections and fatalities
surpassed grim milestones in a reminder the outbreak is far from under control in many parts of the
world.
Futures in New York fell below $38 a barrel after losing 3.2% last week. Deaths from the pandemic
topped half a million, cases rose past 10 million and a United Nations agency reported the most
infections for a single day. A surge in cases across the southern and western U.S. is causing states
including Texas to reinstate measures to halt its spread, threatening the outlook for oil demand.
Prices would likely be falling further if it wasn’t for efforts by the OPEC+ alliance to restrict
production. Iraq -- a habitual laggard when it comes to supply cuts -- is reassessing contracts to
pump crude at fields where costs are high as it tries to contain expenses while curbing production,
in a sign of the commitment within the group to ease a global glut.
After rebounding rapidly from its plunge below zero in April on supply cuts and recovering demand,
crude has fallen in two of the last three weeks. Oil stockpiles in the U.S. are at record highs,

worldwide consumption is still a long way off pre-virus levels and many refiners are struggling with
low margins. There’s also evidence American production is starting to come back, while Norway is
pumping flat out from its new field.
“Oil may have reached its peak in the short run and prices are likely to consolidate over the next
few weeks,” said Howie Lee, an economist at Oversea-Chinese Banking Corp. in Singapore. Prices
have risen enough to encourage the return of marginal producers in the U.S., he said.
West Texas Intermediate for August delivery fell 2% to $37.74 a barrel on the New York Mercantile
Exchange as of 11:26 a.m. in Singapore following an 0.6% decline on Friday. Brent for August
settlement lost 1.9% to $40.25 on the ICE Futures Europe exchange after dropping 2.8% last week.
The global benchmark crude’s six-month timespread was 75 cents in contango, where later-dated
contracts are more expensive than near-dated ones, from 62 cents in contango Friday. The market
structure indicates there is still some concern about over-supply.
In the U.S., Chesapeake Energy Corp, filed for bankruptcy on Sunday, becoming one of the biggest
victims of a spectacular collapse in energy demand due to the virus. Exxon Mobil Corp., meanwhile,
is preparing to cut jobs to create a slimmed-down, more efficient organizational structure.
In a move that has the potential to alter the balance of power between sellers and buyers in the oil
market, China’s state-owned refining giants are in discussions to form a joint purchasing group to
buy crude. The proposal has won the support of the central government and relevant industry
watchdogs, said people familiar with the initiative, who asked not to be identified as discussions are
private and ongoing.
U.S Natural Gas index, Henry Hub dips to record lows, says EIA
Citing Natural Gas Intelligence data, U.S. Energy Information Administration notes that the Henry
Hub reached $1.38 per million British thermal units (MMBtu) on June 16, 2020, the lowest daily
Henry Hub price without adjusting for inflation and in nominal dollars since December 1998.

After starting 2020 relatively low, the price at Henry Hub so far this summer has continued to trend
low because of high natural gas storage levels and declines in natural gas demand, specifically in
exports of liquefied natural gas (LNG) feedgas and in the industrial sector.
Following a mild winter, natural gas inventories ended the heating season on April 30 at 21 per cent
(395 billion cubic feet (Bcf)) higher than the five-year average and 50 per cent (772 Bcf) higher than
last year’s end-of-season levels. Since then, those differences have continued to remain wide as a
result of falling demand, which has increased net natural gas injections into storage.
As of June 12, natural gas storage levels were 17 per cent (419 Bcf) higher than the five-year
average and 33 per cent (722 Bcf) higher than last year.
High storage levels indicate high natural gas production relative to consumer demand. The June
Short-Term Energy Outlook (STEO) forecasts record natural gas in storage of nearly 4.1 trillion
cubic feet by the end of October 2020.
Low feedgas volumes delivered to LNG export terminals in recent weeks have also put downward
pressure on natural gas prices. Natural gas deliveries to LNG terminals have averaged 4.0 billion
cubic feet per day (Bcf/d) so far in June, which is 1.4 Bcf/d lower than feedgas volumes last year
and more than 5.0 Bcf/d lower than the record-high feedgas volumes estimated in late March.
In addition, less business and manufacturing activity stemming from the policies put in place to
mitigate the spread of the 2019 novel coronavirus disease (COVID-19) have also led to weaker
natural gas demand from industrial consumers.

Estimates from S&P Global Platts suggest that average industrial natural gas consumption in June
2020 has declined about 2.1 Bcf/d, or 9.6 per cent, compared to June 2019.
Low natural gas prices so far this summer have resulted in increased natural gas consumption by
electric power plants (power burn) because natural gas has become more competitive for electricity
generation compared to competing fuel sources, such as coal.
The average daily power burn is up about 6 per cent in June compared to last year. This increase
occurred despite essentially flat demand growth for electricity so far this June.
Another effect of historically low natural gas prices is declining natural gas production. According to
data from IHS Markit, dry production totaled about 90 Bcf/d in June, down nearly 3.7 Bcf/d from
March 2020, EIA notes.
The recent declines in demand have outpaced the declines in production, putting downward
pressure on Henry Hub prices. However, further declines in natural gas production are expected as
a result of lags between natural gas price changes and adjustments to production levels.
The June STEO forecasts dry production to continue declining steadily, reaching a low of 84.2 Bcf/d
in May 2021. Declines in natural gas production will put upward pressure on the Henry Hub price in
the coming months. The June STEO expects higher natural gas prices by the end of 2020,
forecasting Henry Hub to average $2.95/MMBtu in December.

Oil refiners adapt to post-lockdown shift to gasoline from diesel
Reuters John Kemp
Petroleum consumption is rising around the world as the major economies exit from lockdowns
imposed to control the coronavirus epidemic, but the uneven recovery presents challenges for fuel
refiners.
Refiners must cope with a much stronger rebound in demand for gasoline compared with diesel and
jet fuel, reconfiguring their equipment to shift the yield towards light distillates and away from middle
distillates.
The epidemic and measures introduced to control it have reduced petroleum consumption in three
ways, with varying implications for the scale and speed of the recovery in fuel use:
First, the direct and indirect effects of mandatory lockdowns as a result of stay-at-home orders
and the closure of some businesses, which sharply reduced personal mobility. Formal
lockdowns had the largest immediate impact on oil consumption because they hit personal
movements, with the main impact on gasoline, the dominant motor fuel in all regions outside
Europe.
But most mandatory lockdown measures have now been reversed, or eased, which has led to
a big increase in mobility and gasoline consumption compared with early April, when lockdown
measures were most intense.

Second, the effects of voluntary behaviour changes, as individuals attempt to avoid crowded
environments with a high risk of virus transmission. Behaviour changes have mostly involved
avoiding mass transit systems and passenger aircraft, ensuring the largest impact has been felt
on jet fuel.
Behaviour changes have proved longer lasting, with scheduled flights and jet fuel consumption
still down by around 50% compared with before the epidemic. Senior airline executives expect
passenger volumes to remain below pre-pandemic levels at least through the rest of 2020 and
2021, so jet consumption will be reduced in the medium term.
Third, the macroeconomic effects of lockdowns and voluntary behaviour changes on household
consumption and business investment, as consumers and firms respond to lower incomes and
sales. The epidemic and lockdowns have triggered a business cycle downturn, which will hit
diesel especially hard since this is the fuel mostly commonly used by manufacturers and freight
transportation firms.
Business cycle downturns take time to reverse fully, so there will be a hit to diesel consumption
through the rest of 2020 and into 2021.
REFINERY FLEXING
Light distillates (gasoline) were the most severely impacted by the first phase of the epidemic, but
have also recovered fastest as lockdowns have eased.
Middle distillates (predominantly diesel but also jet) were less impacted in the first phase, but are
now recovering more slowly and will be harder hit for the rest of 2020 and 2021.

As a result of these dynamics, refining margins for gasoline collapsed in late March and early April,
turning negative for a time, but have since rebounded close to pre-pandemic levels
By contrast, middle distillate margins have been gradually weakening since the start of the year on
a deteriorating economic outlook and show no sign of a significant recovery.
Responding to both price signals and filling storage tanks, refiners slashed light distillate production
at the height of the lockdown in favour of middle distillates – before sharply reversing course in
recent weeks.
In the United States, refiners typically make around 1.5 times more gasoline than jet and diesel
combined. But the ratio fell to 1:1 at the start of April before surging to almost 1.7:1 last week.
Gasoline is the largest output and principal revenue-earner for most refineries in the United States,
so it dominates the decision about how much crude to process.
At the height of lockdown, refineries slashed their crude processing to avoid producing too much
gasoline with no room to store it. As the lockdowns have eased, however, refineries have ramped
up their crude throughput to meet recovering gasoline demand.
The consequence has been the production of too much middle distillate, which has further weighted
on diesel margins.
By restraining crude processing over the next couple of months, refiners should be able to reduce
both gasoline and diesel inventories.
But the degree of normalisation is likely to be greater for gasoline than diesel, which will leave middle
distillate margins struggling.

NewBase Special Coverage
The Energy world - Special 01- June -2020
Satellites reveal major new gas industry methane leaks
Reuters + NewBase
Last fall, European Space Agency satellites detected huge plumes of the invisible planet-warming
gas methane leaking from the Yamal pipeline that carries natural gas from Siberia to Europe.
A undated handout image shows methane emission hotspots associated with oil, gas and coal between
January 2019 and May 2020. KAYRROS/Handout via REUTERS
Energy consultancy Kayrros estimated one leak was spewing out 93 tonnes of methane every hour,
meaning the daily emissions from the leakage were equivalent to the amount of carbon dioxide
pumped out in a year by 15,000 cars in the United States.
The find, which has not been reported, is part of a growing effort by companies, academics and
some energy producers to use space-age technology to find the biggest methane leaks as the
potent heat-trapping gas builds up rapidly in the atmosphere.
Kayrros, which is analysing the satellite data, said another leak nearby was gushing at a rate of 17
tonnes an hour and that it had informed Yamal’s operator Gazprom (GAZP.MM) about its findings
this month.
Gazprom did not immediately respond to requests for comment about the leaks identified by
Kayrros.

Up to now, estimates of greenhouse gas emissions from industries have relied mainly on paper-
based calculations of what’s pouring out of tailpipes and smokestacks, based on the amount of
energy consumed by people and businesses.
But as satellite technology improves, researchers are starting to stress test the data - and the early
results show leaky oil and gas industry infrastructure is responsible for far more of the methane in
the atmosphere than previously thought.
Such a revelation would heap pressure on energy companies – already targeted by climate activists
and investors for their contribution to carbon dioxide emissions - to find and plug methane leaks.
The new satellite discoveries of methane leaks could also lead to more stringent regulatory regimes
targeting natural gas, once seen as a “clean” fossil fuel, as governments seek to combat climate
change, experts say.
While scientists generally agree that calculating emissions based on consumption works well for
carbon dioxide, it is less reliable for methane, which is prone to unexpected leaks.
Methane is also 80 times more potent during its first 20 years in the atmosphere and scientists say
that identifying methane sources is crucial to making the drastic emissions cuts needed to avoid the
worst impacts of climate change.
“What this now shows is that the avoidance of that fossil leakage actually can have a larger impact
than what was anticipated earlier,” said Imperial College London climate scientist Joeri Rogelj, who
is one of the authors for reports by the Intergovernmental Panel on Climate Change (IPCC).

PIVOTAL DISCOVERY
A study in February’s Nature magazine reinforced the idea that the oil and gas industry produces
far more methane than previously thought as it suggested emissions of the gas from natural causes
have been significantly overestimated.
The findings don’t let farming off the hook - it’s still responsible for a quarter of the methane in the
atmosphere - but they suggest mud volcanoes and natural oil and gas seepages have been taking
some of the heat for the energy industry’s leaks.
Some big oil and gas companies such as BP (BP.L) and Royal Dutch Shell (RDSa.L) are tackling
the issue by investing in satellite companies or signing monitoring deals so they can find and plug
their leaks and stick to pledges to slash emissions.
The push to detect emissions from the sky began when U.S. advocacy group Environmental
Defense Fund (EDF) and universities including Harvard used aerial measurements to show
methane leaks from America’s oil and gas heartland were 60% above inventories reported to the
U.S. Environmental Protection Agency.
That 2018 report was pivotal, said Christophe McGlade, a senior researcher at the International
Energy Agency (IEA).
“What they found from actual ground and aerial measurements is that the engineering-based
approach can really underestimate total emissions,” he said. “Maybe if emissions were higher in the
United States than previous estimates, maybe they were higher in other parts of the world too?”
A year later, Canadian greenhouse gas monitoring company GHGSat found another major leak at
pipeline and compressor infrastructure near the Korpezhe field in Turkmenistan.
In an October report, GHGSat estimated the leak released 142,000 tonnes of methane in the 12
months to the end of January 2019 and said then it was the biggest on record.
GHGSat said the leak was plugged in April 2019 after state oil company Turkmen Oil was notified.
Turkmen Oil officials could not be reached for comment. The company declined to comment when
asked about it in November.
“That one emission that we found together represents about one million cars taken off the road per
year,” said GHGSat founder Stephane Germain.
Now, the more recent Kayrros discovery has added to the evidence that undetected methane leaks
from the energy industry are a global issue – and a major one.
RUSSIA IN THE SPOTLIGHT
Kayrros said its analysis of the satellite data showed concentrations of methane around compressor
stations along the pipeline linking Russian gasfields to Europe.
The Yamal-Europe pipeline stretches 2,000 km (1,250 miles) from Germany through Poland and
Belarus to Russia where it joins the 2,200 km SRTO–Torzhok pipeline to Siberia’s gasfields.
Gazprom (GAZP.MM) estimated that about 0.29% of the 679 billion cubic metres of gas it moved
through its pipeline network escaped as methane emissions in 2019. Yamal has an annual capacity
of about 33 billion cubic metres.
“These figures correspond to the best global practices,” Gazprom said in a June 10 statement about
its emissions.

Kayrros also discovered leaks from oil and gas installations in the Sahara Desert in North Africa.
“Early results show that the estimates we have been relying on for the last years and decades are
probably too low and we’re finding more methane coming out of various industries and regions than
we thought was the case,” said Christian Lelong, director for natural resources at Kayrros.
McGlade said the IEA increased the projected contributions of several countries in central Asia
and North Africa in its Methane Tracker this year because of the satellite detections.
An undated handout image shows methane hotspot on the Yamal pipeline. KAYRROS/COPERNICUS
SENTINEL DATA 2019-2020/Handout via REUTERS
He singled out Russia as one country where official methane emissions estimates were likely too
low.

According to current IEA estimates of methane emitting countries, Russia is closely followed by the
United States, with other large oil and gas producers such as Iraq, Iran and Saudi Arabia further
down the list.
“Our estimates suggest that Russia is actually among the higher emitters globally. There does
appear to be evidence from satellites of leaks along some of its large gas pipeline routes,” McGlade
said.
The Kremlin did not immediately respond to requests for comment about the IEA estimates.
MORE SATELLITES
The scrutiny from space is set to intensify. GHGSat aims to launch two new satellites this year while
the EDF advocacy group plans to launch its own satellite in 2022.
The U.S. National Aeronautics and Space Administration (NASA) is also working on a satellite
monitoring programme for greenhouse gas emissions, specifically in the United States.
Shell signed a deal with GHGSat last year to work towards covering its sites globally, saying it hopes
to get its methane leakage rate down to 0.2%, or below, by 2025.

BP is planning to cover its sites with constant measurements by 2023 and invested $5 million this
month in Satelytics, an analytics firm that tracks methane emissions using satellites.
BP, Shell and U.S. non-profit EDF - along with Eni (ENI.MI), Total (TOTF.PA), Equinor (EQNR.OL)
and Wintershall Dea - sent policy recommendations to the European Union in May, asking the
world’s biggest gas importer to standardise the gathering of methane emissions data by 2023, using
satellite technology.
U.S. oil companies have also been exploring ways to detect methane emissions, said Howard
Feldman, senior director for regulatory and scientific affairs at the American Petroleum Institute.
Exxon Mobil Corp (XOM.N), for example, said this year it was field testing eight detection methods,
including satellites and aerial surveillance with drones, helicopters and planes.

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
The Editor :”Khaled Al Awadi” Your partner in Energy Services
NewBase energy news is produced daily (Sunday to Thursday) and sponsored by Hawk Energy Service –
Dubai, UAE.
For additional free subscription emails please contact Hawk Energy
Khaled Malallah Al Awadi,
Energy Consultant
MS & BS Mechanical Engineering (HON), USA
Emarat member since 1990
ASME member since 1995
Hawk Energy member 2010
www.linkedin.com/in/khaled-al-awadi-38b995b
Mobile: +971504822502
khdmohd@hawkenergy.net or khdmohd@hotmail.com
Khaled Al Awadi is a UAE National with a total of 28 years of experience in the Oil & Gas sector.
Currently working as Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“
with external voluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE
operations base , Most of the experience were spent as the Gas Operations Manager in Emarat ,
responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the
years, he has developed great experiences in the designing & constructing of gas pipelines, gas
metering & regulating stations and in the engineering of supply routes. Many years were spent
drafting, & compiling gas transportation, operation & maintenance agreements along with many
MOUs for the local authorities. He has become a reference for many of the Oil & Gas Conferences
held in the UAE and Energy program broadcasted internationally, via GCC leading satellite
Channels.
NewBase : For discussion or further details on the news above you may contact us on +971504822502 , Dubai , UAE
NewBase 2020 K. Al Awadi

New base energy news 29 june 2020 issue no. 1351 compressed

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