New base energy news 24 april 2020 issue no. 1332 by senior editor eng-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 24 April 2020 - Issue No. 1332 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
UAE: DoE launches campaign to showcase energy sector’s
capacity and resilience … WAM/Esraa Ismail/Tariq alfaham
The Abu Dhabi Department of Energy, DoE, has launched a new campaign titled "Our Commitment
– Our Nation’s Power" to highlight the critical role the energy sector plays in supporting communities
and in the continuity of key sectors and maintaining social and economic stability in Abu Dhabi and
the UAE.
The campaign underlines the importance of the electricity and water sector in Abu Dhabi and of the
security of supply to ensure stability for the emirate’s vital industries, in collaboration with the DoE’s
strategic partners.
www.linkedin.com/in/khaled-al-awadi-38b995b

Awaidha Murshed Al Marar, Chairman of the Abu Dhabi Department of Energy, said, "The campaign
is in line with the efforts undertaken by the Emirate of Abu Dhabi and the UAE to ensure stability for
the community and all vital economic sectors, by ensuring an uninterrupted supply of power and
water to all facilities and households.
"The campaign also raises the community’s awareness of the energy sector’s goals, which include
improving their wellbeing while they are confined to their homes."
The DoE Chairman hailed workers at all water and energy facilities, who still have to go to work
daily, thanking them for being on the front line to maintain uninterrupted energy supplies during
these unprecedented conditions.
The ‘Our commitment – Our Nation’s Power’ campaign will highlight the energy sector’s digital
capacity through social media platforms, to promote the use of digital smart services as a showcase
of commitment to supporting remote working and the say at home directives, thus serving the UAE
and safeguarding its best interests.
DoE offers integrated digital services through several channels, including the DoE corporate
website, the Abu Dhabi Energy Services Platform, and the Abu Dhabi Government Services
platform ‘Tamm’.
End users – be they individuals or facilities – can access the DoE’s digital services by registering
on its website, or by using the smart digital ID feature (UAEPASS) and the smart access service to
avail the services on the ‘Tamm’ platform.

Egypt: SDX Energy made successful flow rate test at Sobhi discovery
Source: SDX Energy
SDX Energy, the MENA-focused oil and gas company, has provided an update on well-testing
operations at the SD-12X ('Sobhi'; SDX 100% working interest) discovery well in the South Disouq
Exploration Permit onshore Nile Delta, Egypt (SDX 55% working interest).
The drill stem test (DST) at the Sobhi well began with a step-rate test of one hour achieving a
maximum rate of 25 mmscf/d on a 54/64" choke. This initial flow test was followed by a three hour
period flowing at a stable rate of 15 mmscf/d on a 28/64" choke and then a further four hours flowing
at a stable rate of 10 mmscf/d on a 16/64" choke. The well was then shut in for a 12 hour build-up
period during which pressure continued to increase back to pre-test levels.
From an initial review of the well-test data, it is anticipated that when connected, the well will produce
at an optimum stabilised rate of 10-12 mmscf/d which is in line with the nearby Ibn Yunus-1X
producing well. The Sobhi well is expected to produce mostly dry gas as opposed to gas and
condensate.

Sobhi will be subject to a longer rig-less test in the coming weeks which will provide more data to
help determine the recoverable volume in the discovery, which at present management estimates
to be 24 bcf of recoverable resource. The exact timing of the rig-less test will be dependent on the
timing of the mobilisation of equipment which may be impacted by ongoing Covid-19 restrictions in
the region.
Management expect that the Sobhi well will be tied in during 2021 via a 5.8 kilometre tie-in to the
Ibn Yunus-1X location where an existing flow-line connects to the South Disouq Central Processing
Facility. On a gross basis, the tie-in cost is estimated at US$3.5 million.
The discovery will potentially only require one further development well to be drilled, which will not
be necessary for another two to three years. SDX drilled the Sobhi well at a 100% working interest
and the total cost of the well, including the cost to complete, is estimated at US$3.7 million.
Under Clause 8.5 of the Joint Operating Agreement, 'Premium to Participate in Exclusive
Operations', if the Company's partner elects to participate in the well now that a discovery has been
made, it is required to pay its full 45% share of the well cost, plus a premium of a further 300% of
this amount.
Mark Reid, CEO of SDX, commented:
'We are pleased with these initial well test results which confirms that we have a commercial
discovery at the Sobhi well. This discovery increases our South Disouq 2P reserves by
approximately 50% given that we sole risked the well.
Furthermore, Sobhi has the potential to extend the current South Disouq plateau production of 50
mmscfe/d through to 2023/24 with a low-cost tie in to our existing gas processing plant. To have a
commercial gas discovery of this scale at South Disouq is especially pleasing in the current
environment as our low cost, fixed price gas development will continue to be highly cash generative
for longer.'

Oman: Sohar Port is first ME port to join SEA-LNG coalition
Oman Observer + NewBase
Muscat: Sohar Port and Freezone (SOHAR) has announced its membership of SEA-LNG to
promote its investment in LNG bunkering facilities and the use of liquefied natural gas (LNG) as a
marine fuel.
SEA-LNG is the leading multi-sector industry coalition, created to accelerate the widespread
adoption of LNG. Marsa LNG, a venture comprised of Total SA and OQ, is developing a state of the
art LNG liquefaction plant and bunkering facility in SOHAR Port.
Highlighting the importance of the upcoming project, Mark Geilenkirchen, CEO of Sohar Port said;
“This major LNG Bunkering project will generate in-country value and job opportunities, and will
support industry diversification efforts by promoting shipping activities in Oman.
The establishment of this facility will make SOHAR one of the key LNG bunkering facilities on the
main shipping trade routes, alongside other strategic ports, many of whom are already SEA-LNG

members, such as the Port of Singapore. Marsa LNG will supply LNG sourced locally in the
Sultanate.”
The project will see the provision of LNG to the shipping lines calling at SOHAR Port. The switch
from traditional marine fuel oils to LNG has accelerated following the implementation of new sulphur
emission limits by the International Maritime Organization (IMO) in January 2020 and the IMO
greenhouse gas emission targets set for 2030 and 2050.
Peter Keller, Chairman of SEA-LNG said; “We are excited to welcome SOHAR to the SEA-LNG
coalition. SOHAR is our first member from the Sultanate of Oman and will provide an attractive
global offering once the marine bunkering project is completed.
From our perspective, this is an opportune time to develop LNG capabilities in Oman given the
expansive growth of marine activity within the region. We welcome SOHAR to our cause of
furthering the use of LNG as an important, environmentally superior maritime fuel.”
Due to its unique location outside the Strait of Hormuz and mid-way between Europe and Asia,
SOHAR is ideally positioned to become a major LNG bunkering hub in the Middle East. In addition,
SOHAR Port and Freezone feature deep-water drafts capable of handling the largest vessels in the
world. The liquefaction plant and bunkering project will be able to offer attractive business
conditions, further enhanced by access to a dedicated logistics chain as well as large domestic gas
reserves.
Peter Keller continues: “As well as providing a means to comply with recently enforced sulphur
limitations, LNG provides a clear pathway for the shipping industry to decarbonise through the
introduction of biomethane and synthetic methane. Now is the time to move forward with LNG as
an important maritime fuel.
Inaction is not a plan and we cannot afford to wait decades for solutions that may never be
realised. Investing in LNG capable vessels now provides the shipping industry with a pathway to a
low carbon future as well as significant and immediate environmental and health benefits.”
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Tunisia: Zenith Energy acquires Sidi El Kilani from KUFPEC
Source: Zenith Energy
Zenith Energy has announced that its newly created wholly owned subsidiary Zenith Energy
Netherlands has signed a conditional sale and purchase agreement ('SPA') with KUFPEC (Tunisia),
a 100% subsidiary of Kuwait Foreign Petroleum Exploration Company, a subsidiary of the State of
Kuwait's national oil company, for the acquisition of a working interest in, inter alia, the North
Kairouan permit and the Sidi El Kilani Concession, which contains the Sidi El Kilani oilfield ('SLK').
The Seller holds an undivided 22.5% interest in the Tunisian Acquisition, together with 25 Class B
shares in Compagnie Tuniso-Koweito-Chinoise de Pétrole (CTKCP), the operator, representing
22.5% of the issued share capital of the company.
Zenith's partners in the Tunisian Acquisition will include the national oil company of Tunisia,
Entreprise Tunisienne d'Activités Pétrolières (ETAP) with a 55% interest and CNPC, China National
Petroleum Corporation with a 22.5 % interest.
The Seller has agreed to sell, assign and transfer to Zenith Netherlands the Tunisian Acquisition on
the terms and subject to the conditions set out in the SPA.
The consideration payable by Zenith Netherlands under the SPA is US$500,000.
Completion of the Tunisian Acquisition is conditional on approval being granted by the Comité
Consultatif des Hydrocarbures of the Republic of Tunisia in respect of the transfer of the Seller's
right, title and interest in and under the SLK Concession to Zenith Netherlands.
As first announced on March 2, 2020, Zenith is currently in negotiations with an international oil
major to sign an offtake agreement for the asset's future oil production in order to fund the Tunisian
Acquisition and its development post-completion.
Tunisian Acquisition Highlights
 First discovered in 1989 by KUFPEC with commercial production commencing in 1993 and
reported to be the second largest oilfield discovered in Tunisia since 1989.

 SLK reached a peak production of c. 20,000 boepd in 1995.
 Covers an area of 204 sq kms, located onshore, in the Pelagian Basin, Eastern Tunisia.
 SLK is one of the most productive fields in onshore Tunisia and currently produces, natural
flow, at a rate of approx. 700 bopd.
 Generates gross annual revenues of approx. US$15 million.
 SLK produces 39 API gravity oil from a fractured carbonate reservoir (Abiod Formation), at
a depth of c. 1,600 metres. The reservoir characteristics are enhanced by natural fractures
and locally by dolomitisation.
 SLK Facilities include a permanent Gas Oil Separation Plant (GOSP) and a Pipeline of 125
km x 8" diameter, 22,000 bpd capacity from the field to La Skhira terminal.
Zenith expects to soon commission a new Competent Person's Report in compliance with Canadian
securities laws, specifically the COGE Handbook and National Instrument 51-101 - Standards of
Disclosure for Oil and Gas Activities, in order to obtain an updated reserves evaluation for the
Tunisian Acquisition.
Andrea Cattaneo, Chief Executive Officer, commented:
'We are delighted to have executed the SPA with regards to the interest in the Sidi El Kilani
Concession, a highly productive Tunisian onshore oil production and development asset, which has
consistently outperformed even the most optimistic production forecasts since commercial
production commenced in 1993.
The Board views Tunisia as a safe, democratic jurisdiction with a well-established history of
successful oil and gas production activities for junior, independent companies such as Zenith. Upon
completion of this deal, Zenith will have material production revenue for reinvestment in field
development activities. Our strategic outlook is that oil prices will progressively strengthen in line
with a gradual worldwide recovery in financial and industrial activity following the progressive
alleviation of the devastating COVID-19 pandemic.
The current low oil price environment provides an unprecedented opportunity for companies wishing
to expand countercyclically by securing large, revenue generating oil and gas production assets at
advantageous terms. I am also delighted to have initiated a fruitful relationship with KUFPEC, a
highly respected subsidiary of Kuwait's State Oil Company with operations across the world
including Norway, and I look forward to exploring further cooperation opportunities in the future.'

U.S: COVID-19 mitigation efforts result in the lowest U.S.
petroleum consumption in decades …: U.S. EIA, Weekly Petroleum Status Report
U.S. consumption of petroleum products has fallen to its lowest level in decades because of
measures that limit travel and because of the general economic slowdown induced by mitigation
efforts for the coronavirus disease 2019 (COVID-19). The U.S. Energy Information Administration
(EIA) estimates the decline in petroleum product demand by examining the changes in total product
supplied, EIA’s proxy for consumption.
As outlined in EIA’s Weekly Petroleum Status Report, published yesterday, total petroleum demand
averaged 14.1 million barrels per day (b/d) in the week ending April 17, up slightly from 13.8 million
b/d in the previous week—the lowest level in EIA’s weekly data series, which dates back to the early
1990s.
The most recent value is 31% lower than the 2020 average from January through March 13, or
before many of the travel restrictions began. In the week ending April 3, total U.S. product
supplied of petroleum products fell by 3.4 million b/d, the largest weekly decline in EIA’s data
series. Changes in the weeks since then (weeks ending April 10 and April 17) have been more
muted, suggesting that consumption is stabilizing.

Total petroleum demand measured as product supplied consists mostly of motor gasoline (45% of
the 2019 total), distillate fuel oil (20%), jet fuel (9%), and chemical feedstocks and other fuels (26%).
EIA uses estimates of product supplied from the Weekly Petroleum Status Report (WPSR) as a
proxy for consumption because WPSR reports the amount of petroleum products that leaves the
primary supply chain for ultimate delivery to consumers.
The timing of changes in product supplied might not align with end-use consumption patterns
because of variations in the timing of when respondents (such as refineries, importers, and bulk
terminals) report movements of products within the primary supply chain.
Motor gasoline consumption has declined the most in absolute terms. Before many businesses were
shut down and stay-at-home orders were issued, motor gasoline product supplied averaged 8.9
million b/d, based on 2020 data through March 13. Since then, motor gasoline product supplied has
fallen 40% to 5.3 million b/d as of the week ending April 17. T
his decrease in motor gasoline product supplied accounts for 54% of the total change in product
supplied. U.S. consumption of jet fuel experienced the largest drop in relative terms, declining 62%
from a pre-shutdown average of 1.6 million b/d to just 612,000 b/d on April 17.
The decline in distillate fuel oil consumption so far has been less severe than the changes in motor
gasoline and jet fuel. Through March 13, distillate product supplied averaged 3.9 million b/d in 2020.
By the week ending April 17, distillate product supplied was 20% lower, at 3.1 million b/d. Distillate
fuel oil is primarily consumed as diesel fuel, the predominant fuel of the trucking, locomotive, and
agricultural sectors. Continued demand for distribution of necessities such as food and medical
supplies and increased home deliveries for goods likely contributed to relatively stable demand for
distillate fuel in the initial weeks following the shutdown.

NewBase April 24-2020 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices extend rebound on output cuts, still set to end
tumultuous week in the red … Reuters + Newbase
Oil prices rose on Friday, gaining further ground as some producers like Kuwait said they would
move to cut output swiftly to try to counter the evaporation in global demand for fuels caused by the
coronavirus pandemic.
Brent crude was up 77 cents, or 3.6%, at $22.11, having climbed 5% on Thursday. U.S. oil gained
66 cents, or 4%, to trade at $17.16 a barrel, after surging 20% in the previous session.
Oil price special
coverage

But barring a sharper jump on the last trading day of the week, prices are heading for their eighth
weekly loss in the last nine — one of the most tumultuous weeks in the history of oil trading, with
U.S. West Texas Intermediate falling into negative territory to minus $37.63 a barrel on Monday,
while Brent thudded to a two-decade low.
“The disruption relating to the coronavirus is set to cause the steepest fall in global GDP since the
Second World War,” Capital Economics said in a note, forecasting a 5.5% contraction in global
economies this year, dwarfing the 0.5% fall seen during the global financial crisis.
“Once the virus is under control output should rebound, but it will take years to return to its pre-virus
path,” it said.
Under a deal agreed between the Organization of the Petroleum Exporting Counties (OPEC) and
associated producers like Russia, a grouping known as OPEC+, production cuts equal to 9.7 million
barrels of oil per day are due to kick in from May.
But Kuwait’s state news agency KUNA said on Thursday the producer will begin cutting supplies to
international markets without waiting for the official start of the OPEC+ deal.
Meanwhile Azerbaijan’s Azeri-Chirag-Guneshli oil project will have to cut output sharply from May
onwards as the oil producer fulfills its commitments under the deal to cut production, four sources
told Reuters.

US fracking set for the biggest monthly decline in history as oil
prices collapse and Covid-19 persists - Rystad Energy
The Covid-19 pandemic has ravaged global oil demand and, coupled with the extremely low price
levels brought on by the wide supply surplus, is likely to cause the largest monthly drop in fracking
activity ever recorded in the US, a Rystad Energy analysis shows.
We estimate that the total number of started frac operations will end up below 300 wells in April
2020; close to 200 in the Permian and less than 50 wells each in Bakken and Eagle Ford. This
translates into a 60% decline in started frac operations between the peak level seen in January to
February 2020 and April 2020, as the majority of public and private operators implement widespread
frac holidays.
In March we observed an extreme 30% monthly decline in the number of started frac jobs in these
three major oil basins, a fall from 807 in February to just 550. Also, nationwide fracking activity, on
a completed jobs basis, might have already declined by around 20% in March 2020, according to
our estimates.
'With such a rapid decline in fracking already visible, very little activity will be happening in the oil
basins during the remainder of the second quarter of 2020. The natural base production decline,
which we have seen as an absolute floor for production, therefore becomes an increasingly relevant
production scenario,' says Rystad Energy Head of Shale Research Artem Abramov.
Get access to the complete coverage of the North American well data with ShaleWellCube.
If we assume that no new horizontal wells are put on production from April 2020 onwards, total LTO
production will decline by 1 million barrels per day (bpd) by May, 2 million bpd by July and by 3
million bpd by October to November, with the Permian Basin accounting for more than half of
nationwide base decline.

US light oil operators, which are now announcing voluntary production curtailments, will try to deliver
on these cuts as much as possible from the natural production decline, as opposed to shut-ins of
producing wells (though some of the marginal, least economic volumes are being shut in, too).
The magnitude of the base decline for US LTO sounds extreme in the context of what we see for
other supply sources globally. But ironically, the steep decline is actually too late to save prices;
despite the oversupply issue, standard operation patterns prevent operators from simply turning the
faucet off. These days Permian wells require about two months from the moment frac operations
start until they produce first oil, and require about three months before they reach peak output.
Hence, the decline in started jobs which began in March will result in a lower number of wells put
on production in May, which ultimately will lead to a drop in peak production in June if normal
operational patterns are maintained.
'On the demand and storage side, the market is already moving through its toughest challenge yet,
and the WTI front-month sell-off emphasized how broken the physical market might be already. We
are therefore concerned that significant production shut-ins will be required in the next few weeks
to bring the market into the balance in a brutal manner,' adds Abramov.
In addition to our standard analysis of frac activity, based on incomplete FracFocus reporting in
recent months and empirical reporting delay adjustment factors, we are now rolling out a brand new
way of filling the gaps left by official reporting. We have begun using satellite data to systematically
monitor more than 40,000 permitted and drilled locations across the US, continuously identifying
the presence of any activity taking place.
Our methodology is based on monitoring the equipment intensity on each pad or permitted location
and then analyzing the evolution of this intensity over time to identify the main pre-production
activities in each well life cycle, from pre-spud to main drilling and fracking.
For more analysis, insights and reports, clients and non-clients can apply for access to Rystad
Energy’s Free Solutions and get a taste of our data and analytics universe.

NewBase Special Coverage
The Energy world - Special 24- April-2020
Do U.S. Shale Drillers Deserve To Exist In Free Markets?
Mitchell McGeorge Oilprice.com
In the fallout of the current crisis, one more statistic can be added to the toll of Covid-19 – US Energy
Independence. The Shale Revolution was responsible for the growth in US oil and gas production
that lead to the President, Energy Secretary and industry bodies heralding the era of US energy
independence and US energy dominance.
But, with the oil markets in turmoil, US shale producers who account for over two-thirds of US
production (and in particular the Permian Basin which accounts for almost forty percent of total US
production) have been ‘tapping the mat’ urging President Trump to save the industry through various
means of subsidies, bailouts and tariffs.
Shale producers have been arm-twisting
US politicians into cringeworthy calls with
Saudi Arabian officials because of their
belief that Saudi Arabia, as a strategic
ally, shouldn’t be following free market
practices to harm the US Energy
Independence narrative they all
promoted.
So much for the US being the world’s
champion of the ‘free market’!
US shale producers have firmly placed
Saudi Arabia as the ‘bogey-man’ of their
current problems, accusing them of
taking advantage of the global pandemic
to use predatory pricing to dump excess
oil into the North American market.
What they are so conveniently forgetting is that it was left to OPEC/OPEC+ shouldering production
cuts since December 2016 which kept oil prices at a level that meant that shale producers were
able to propel the US to become the largest oil producer in the world.
As the US kept producing more, negating the previous OPEC/OPEC+ production cuts and bringing
the balance of global oil supply under pressure, OPEC/OPEC+ continued to cut more. But hey, it
was all about ‘free markets’ they would say, and the party continued fuelled not responsibly by well
performance and free cash flow – but by a gorging on cheap and readily available debt.
But the US shale market was blowing up before the Coronavirus came along. As is the case with
most viruses, it doesn’t kill you, it just makes the weaker ones more obviously weak.
A bloodbath is coming with record Chapter 11 bankruptcies expected in US upstream E&P
companies. Equity markets had long turned off from the ‘growth at all costs’ shale story, leaving
banks, credit markets and Private Equity companies that know more about raising money than
investing it, as the sources of funding the unsustainable (i.e. loss making) production growth.

They will now have to choose which are the best positions to support through the crisis and which
ones will go. How did we get here? Like all parties, eventually they end, most of their own accord,
the more out of control ones when the house burns down.
US Shale has been eating OPEC’s lunch
In December 2016, after eighteen tough months of lower oil prices following the July 2014 crash,
OPEC instituted the first of its production cuts. The commentary at the time was that Saudi Arabia
was abandoning its attempt to ‘bankrupt’ the US shale industry. US shale gave itself a victory lap of
celebrating its resilience and lower cost base – the mantra was shale could pay its way – and they
believed it.
When OPEC complained that its balancing of the market was artificially supporting the market for
shale’s growth, they were told that it was all about free markets and the President called them a
cartel.

The business model - growth at all costs
The truth was it wasn’t about greater business efficiency and self-funded development, it was about
the massive pump of liquidity by equity, debt and credit markets that encouraged shale producers
to pursue a ‘growth at all costs’ model.
No one cared about self-funded development, free cash flow and real profits, it was all about the
growth in the Permian which saw acquisitions top $100K an acre. The markets had something to
sell and were throwing money at producers, backstopping aggressive merger, acquisition and
production strategies.
But it was a house built on sand. At the commencement of the ‘growth at all costs strategy’ in 2016,
of 40 dedicated US shale companies analysed by Rystad, less than half were operationally cash
flow positive over capex. By 2019 that had dropped to less than 10%.
Following the sharp collapse in oil prices at the end of 2018 equity markets had stopped believing
the shale story, slashing the market capitalisations of E&P listed stocks and limited equity was raised
after 1st quarter 2019. But, in a lower for longer interest rate environment, private equity, debt and
credit markets continued to fund the shale story. But even then, the shale market story started to
lose its followers through 2019.

After commencing a trade war with China in late 2018 that saw the sentiment towards global growth
take a hit (as did oil prices), President Trump announced an increase in the size and scale of the
Trade War in August 2019. Trump threatened China with $300B in additional tariffs which led to the
largest one-day fall in oil prices for four years.

In response, economic growth forecasts were slashed and whilst the threat of the increase in tariffs
was ultimately walked back, the damage was done. Bond yields fell to such an extent that the bond
curve inverted signalling a looming recession and China looked to elsewhere for its oil imports.
With the continuing aggressive tariff rhetoric from Trump we can see that from this point the narrative
of the oil market changed from one of hope for modest recovery and growth to one of looming
recession and falling demand. Whilst backwardation steepened as the markets came to see the
party was ending, producers continued their growth at all costs strategy and production continued
to hit record highs month-on-month.
The shale industry started being asked to produce positive financial results — not just promises of
new super wells, cube development or artificial intelligence. Unfortunately, the industry hasn’t
delivered profits while arguably drilling all the best acreage during these last five years.
The world’s gone mad - drilling your ‘best’ wells at the biggest discount
The growth at all costs reached an absurdity when, due to the debt fuelled increase in production,
spurred on by the debt and equity pushing investment banks and their fee driven models, volumes
produced in the Permian greatly exceeded the takeaway capacity of pipelines, rail and road.
The shale industry’s never-ending growth belief saw Producers flat to the floor selling production for
almost a year from what were their best wells at discounts of up to $18/barrel to WTI. The business
plan was ‘grow, grow, grow’ – all that mattered was higher initial production numbers – then raise,
borrow or both. The thought of making a profit was the furthest thing from the minds of the producers
and their enablers – just grow – the profits will come.

“It’s the debt, stupid……”
But the profits didn’t come and as James Carville said in 1992, ‘It’s the economy, stupid’ as a
statement of the obvious. For the shale market (beyond steep decline curves, takeaway issues,
degrading well quality and high-cost of production), there is one issue that above all others ensures
that the party will end with the house burning down – debt. Debt is always the difference between
being able to tighten your belt and survive a downturn to finding yourself in a death spiral until you
hit Chapter 11.
Of the 40 shale companies that we saw with very limited free cash flow above capex, the debt
obligations between 2020 and 2026 total approximately $100 billion. This is systematic not just of
those 40 companies but the US independent oil producers and even the majors.

As long as shale firms could keep borrowing and losing money to drill new wells, producing more
oil was simple. When profits weren’t a concern, the debt-heavy business model worked. But similar
to other boom and busts, if you want to stay in business, you need to make a profit.
You can’t repay debt if you can’t cover costs
If the current $20 WTI oil price continues or even rises to $30, the US shale industry will find itself
unable to cover every day operating expenses, let alone repay debt as it falls due. From the
Industry’s own figures in the recent Dallas Fed Survey of 95 E&P companies (March 11 – 19) there
is zero free cash flow for the overwhelming number of US E&P companies with a WTI price at
$20.
And when you can’t pay the debt……Chapter 11

Rystad Energy projects that there would be up to 393 US E&P companies that would be forced into
Chapter 11 during 2020 if WTI remained at $20. To reference what this would look like, over the
entire five year period to 1st of April 2020 (which includes the large portion of the last downturn),
215 producers had filed for bankruptcy since Haynes and Boone’s Oil Patch Bankruptcy Monitor
began tabulating E&P filings, involving more than $129 billion in aggregate debt.
For any E&P companies seeking debt - “winter is coming….”
When we look at both charts what we see is the High-Yield Energy Sector on the right showing the
severe deterioration in energy sector market sentiment. This deterioration in high yield has led to a
general downgrading with even the investment grade energy spreads twice as wide as the broader
index.

Premium: Oil Storage Nears Its Limit
As the weaker energy companies start to enter Chapter 11, the market will grow increasingly
negative towards all energy debt. This will begin a stampede to exit energy debt at any price,
causing further dislocations to the market and blow out already wide bid/offer spreads.
These issues manifest themselves in corporate roll risk for all energy companies, not just the weaker
ones or those with 2020 maturities.
Energy companies will be forced to become ‘price-takers’, rolling debt at any cost (if they can get it)
and incurring significantly higher fees when they do. But, as they always do, they will see this as a
risk worth taking, seeing the bigger risk as access to liquidity rather than the price, gambling that
higher oil prices and increased volumes will let them trade out of difficulties.
The problem is that they never trade out of difficulties, the cost of the high-priced new debt is control
of every aspect of operations and cash-flow. They become ‘zombie’ companies – ‘hosting’ the debt
holders and only increasing the probability of their insolvency at a time that suits them.
But can’t we solve all of this with tariffs on Saudi Arabia?
One of the recurring themes from the shale industry since the Oil Price War commenced is putting
tariffs on Saudi Arabian oil imports, like some magic silver bullet that will amazingly save an industry
that hasn’t had the discipline to push itself away from the debt buffet table. But, how is this going to
work and has anybody thought this through beyond an initial ‘emotional’ reaction?
If we look at the US EIA data from its ‘Top sources and amounts of US petroleum imports and
exports’ for 2019, one has to question how a ‘go-alone’ tariff on Saudi Arabian imports would have
any effect at all on global oil prices and the price received by US producers. In 2019 the US imported
on average 9.12 million barrels per day. The top 5 locations from which the US imported in 2019
were:
Country - Barrels/Day -Percentage
Canada - 4.42 million 49%
Mexico 0.65 million 7%
Saudi Arabia 0.53 million 6%
Russia 0.51 million 6%
Colombia 0.37 million 4%
The US receives 56% of its imports from Canada and Mexico and just 6% from Saudi Arabia. By
the US going alone and putting a tariff on Saudi oil, what effect would it have on the oil price achieved
by US producers when just a negligible 6% comes from the affected country?
How would this lead to a price rise in global oil prices when the global demand has collapsed by
more than 30%? As it is, Saudi oil exports to the US have more than halved between 2014 (1.166
million) and 2019 (0.53 million).

What are the risks to the US of a ‘go-alone’ tariff on Saudi imports? In 2019 the top 5 locations to
which the US exported were:
Country - Barrels/Day -Percentage
Mexico 1.19 million 14%
Canada 1.01 million 12%
Japan 0.59 million 7%
S. Korea 0.58 million 7%
Brazil 0.49 million 6%
The US exports a combined total of 26% to Canada and Mexico. Assuming Canada and Mexico
remain with the US, this still leaves 74% of exports available for Saudi export. The top 6 locations
of Saudi exports in 2019 were:
Japan 12.2% China 11.7%
S. Korea 9.0% India 8.9%
U.S.A 8.3% UAE 6.7%
Considering the rancour of the ‘America First’ policy on trade, it is extremely unlikely that the US
could form a coalition with other countries to tariff Saudi oil. China and India have been large
importers of Iranian oil in violation of US embargos. With the miniscule amounts, numerous other
destinations for Saudi exports and the risks of long-term damage to the relationship with an
important ally for a short-term solution, tariffs will have no effect whatsoever.
What about trying to wait out the ‘short-term’ correction until you can
develop again?
The default model is to always think that you can ride out any correction by viewing them as ‘short-
term’ and then going back to business as normal. Unfortunately, with global demand destruction
above 30% and a virus that points to the global economy taking longer than first anticipated to
recover, no one knows how long the Producers will have to hold out.
With WTI stuck around $20, nearly every producer is a long way from being able to cover costs let
alone develop again. In the most recent survey by the Dallas Fed of 92 upstream E&P companies,
WTI prices need to be above $50 for almost all plays before wells can be drilled profitably.
The idea that upstream E&P companies will be able to hold out until development wells can be
drilled profitably again is tenuous at best. With mounting debt loads, interest and maturities most
won’t be able to last beyond the next six months.

If the WTI price continues at $20, Rystad’s predictions show that Lower 48 production could drop to
approximately 6 million barrels by the end of next year.

Have the best shale wells already been drilled?
There is no doubt that shale wells with the right geology can produce a lot of oil and gas. The
problems encountered with shale wells are that they decline rapidly, are at a higher cost point and
we have seen that lately they tend to more gas more quickly than before (which only further
diminishes the economic case – especially when you have to resort to flaring or paying to have gas
taken away).
As the pressure has grown on shale producers to operate at a profit, the era of ‘super wells’, cube
development and AI has been ushered in. But well performance has been declining and initial
production expectations have been worse than the wells that came before, which puts the viability
of the whole shale business model in focus and leads us to question “has the best rock already
been drilled”?
‘Child’ wells are the secondary wells used to infill a Project that is drilled close to an existing ‘parent’
well. Generally, the expectation had been that the performance and recovery of the child well would
mimic the parent providing the basis for the development funding! Current well performance data
suggests that child wells, when drilled close to a parent, not only do they not perform as expected
but they cannibalise the existing production from that parent well. But, spaced further apart, risks
leaving oil in the ground.
Subsequent well performance in the Permian has seen instances where the child wells are
producing between 20% and 30% less than the parent wells. When extrapolated across a Project,
the entire business case for the funding that was provided on the infill drilling model, ceases to be
viable. This is a problem not just for that particular Project, but for the shale industry as a whole.
Does shale have a future?
Up until now, the basic premise of the shale business model has been growth orientated and to drill,
drill, drill and the income will come. A company would drill a high-volume well, hype to the press this
well and the many now proven undeveloped wells on the rest of its acreage, and promise a bright
future, all while borrowing huge sums of money to drill and frack the wells. Now, shale
companies need to do that with oil wells that may not produce as much.
Fundamentally, the business model of the upstream E&P shale companies is broken and outdated.
Funding assets, that in an energy transition climate cannot be classed as ‘growth’, the producers
and investors need to move beyond the old equity and debt models.
The upstream E&P industry needs the funding model to be less based on debt and equity at the corporate
level and more based on well-by-well funding at the Project level. The current debt model fails to consider
the unique characteristics of the decline of the shale wells – having producers pay back capital and interest
in the short period of time that a shale well produces economically recoverable oil and gas. In normal price
environments, let alone with ‘black-swan’ events like the Coronavirus, it is hard enough to make this
economical with the threat of an E&P industry that faces being wiped out.
The investment, operational and management expectations will change but the result will be an industry that
can produce on a more sustainable level without the corporate being burdened by any debt and interest or
highly dilutive equity issuances. A ‘partnership’ between the investor and the producer, where capex is fully-
funded and returns are via a share of resultant production over a period of time no matter what the oil price
will become the standard operating model for a sustainable upstream E&P industry, resulting in long-term
stability and job security.
In 2012, Rolling Stone Magazine referred to the fracking industry as a scam while profiling the late Aubrey
McClendon – I would contend that the current funding model is the scam – the industry would more than
survive, it would thrive with a different funding model.

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

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New base energy news 24 april 2020 issue no. 1332 by senior editor eng-compressed