New base energy news 23 january 2021 issue no 1400 senior editor eng- khaled al awadi-compressed

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NewBase Energy News 23 January 2021 - Issue No. 1400 Senior Editor Eng. Khaled Al Awadi
NewBase for discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Oman: Sumitomo Corp consedering hydrogen project in Oman
Oman Observer - Conrad Prabhu
LANDMARK VENTURE: MoU with ARA Petroleum to study feasibility of producing hydrogen from
associated flare gas to power electric vehicles
Adding further momentum to the Sultanate’s ambitions to evolve into a global hub for hydrogen
production as a zero-carbon energy source, Japanese conglomerate Sumitomo Corporation is
weighing plans to develop a first-of-its-kind hydrogen plant in Oman in partnership with a local
upstream energy firm.
Tokyo-headquartered Sumitomo Corporation announced on Friday that it has kicked off a study
jointly with ARA Petroleum LLC, an Omani oil and gas producer, into the feasibility of establishing
a hydrogen hybrid project with the hydrogen output earmarked primarily for the operation of electric
vehicles in the Sultanate. This follows a Memorandum of Undersigned signed by the two sides in
March last year.
The landmark project centres on a proposal to establish a hydrogen supply chain based on the local
production and consumption of hydrogen, among other byproducts, at one of ARA Petroleum’s
existing hydrocarbon production sites in the Sultanate.

ARA Petroleum, wholly owned by The Zubair Corporation, currently operates the adjoining Blocks
44 and 31 in the northwest of the country. Block 44, with its producing Shams field, has long been
a source of hydrocarbons, chiefly natural gas.
At the heart of the proposed project is a ‘blue hydrogen’ component featuring a hydrogen production
facility generating annually around 300-400 tonnes of hydrogen from associated flare gas generated
at the site.
This energy stream will be chiefly utilised as a fuel for electric vehicles that ARA Petroleum plans to
introduce as part of its operations.
Carbon dioxide (CO2) generated as a byproduct of the process is proposed to be utilised in local
industries, according to Sumitomo. Significantly, electricity for the operation of the plant will come
from a 20 megawatt solar photovoltaic (PV) based project that will be installed nearby.
Over the past two years, the Sultanate has embarked on an ambitious strategy to invest in large-
scale hydrogen production capabilities by harnessing solar and other renewable energy sources to
mass produce hydrogen, billed as an ‘eco-friendly fuel of the future’. ‘Green Hydrogen’ projects are
planned in Suhar and Duqm, with an eye on export markets, thereby helping supplant hydrocarbons
as the country’s main revenue source.
The Sumitomo — ARA Petroleum initiative seeks to employ steam-reforming technology to produce
hydrogen from natural gas. Hydrogen produced from this process is typically known as ‘Blue
Hydrogen’.In a statement, Sumitomo Corporation — a Fortune 500 global trading and business
nvestment powerhouse — said the proposed Oman venture illustrates its commitment to
transitioning towards low and zero-carbon based energy future.
“While contributing to decarbonisation and cleanliness of oil and gas production activities through
the project, Sumitomo Corporation is considering expanding the model of the project both in Oman
and overseas in the future,” the trading giant said.
“Sumitomo Corporation expects hydrogen to be one of the important energies in the future, and
promotes hydrogen related business such as local production and consumption projects and large-
scale value chain projects, that utilises the regional requirements of energy and the characteristics
of hydrogen.
“In order to greatly contribute to the achievement of our long-term goals towards climate change
mitigation, ‘Carbon neutralisation in 2050’ and ‘Realisation of a sustainable energy cycle’, we will
accelerate our efforts for the materialisation of a hydrogen society by promoting hydrogen related
businesses,” the conglomerate added.

Egypt: Mubadala Petroleum signs Concession Agreement for
Red Sea Block 4 .. Source: Mubadala Petroleum
Eng. Tariq Al-Mulla, Egyptian Minister of Petroleum and Mineral Resources, has signed the
concession agreement with Mubadala Petroleum for oil and gas exploration activities in the Red
Sea Block 4, with an area estimated at 3084 km2, owned by the South Valley Egyptian Petroleum
Holding Company (Ganope).
The block was awarded by the Government of Egypt in the 2019 Red Sea Licensing Round.
Following the signing, Mubadala Petroleum will hold 27 percent participating interest in Block 4,
which is operated by Shell with a 63 percent participating interest and Tharwa, with a 10 percent
participating interest.
Block 4 is located in the Northern Red Sea in an area adjacent to the prolific Gulf of Suez basin.
The concessionhas the potential to unlock substantialnew prospects. The work commitment for the
block is to conduct subsurface studies and to acquire 3D seismic during the initial three-year term.
Dr. Bakheet Al Katheeri, Mubadala Petroleum’s Chief Executive Officer, commented:
'The addition of Red Sea Block 4, marks a further extension of our Egypt portfolio with a new high
impact growth opportunity alongside a world class partner in Shell. This new exploration block will
support our strategy of finding and, if successful, developing hydrocarbons for Egypt’s expanding
market and delivering organic growth opportunities to add toour existing business in the country.'
In addition to Red Sea Block 4, Mubadala Petroleum has a 10% stake in the 'Shorouk' concession,
containing the producing 'Zohr'gas field, and a 20% stake in the 'Nour' exploration concession, both
located in the Mediterranean Sea offshore Egypt.

Oman: Regulator prepares to licence 500MW solar PV project
Oman Observer - CONRAD PRABHU
Landmark scheme: The announcement comes as Shams Ad-Dhahira Generating Company
(SAGC) gears up to commission the 500 MW capacity scheme ahead of full commercial operation
targeted around the middle of this year.
The Authority for Public Services Regulation (APSR) is preparing to grant a generation licence to
Shams Ad-Dhahira Generating Company SAOC (SAGC), which is implementing the Sultanate’s
biggest solar photovoltaic (PV) based power plant in the Wilayat of Ibri in the northwest of the
country.
The announcement comes as SAGC, backed by Saudi-based global power and water sector
developer ACWA Power, prepares to commission the 500 MW capacity scheme ahead of full
commercial operation targeted around the middle of this year.
The proposed Generation Licence (Renewable Energy), once approved, will be effective for a period
of 25 years, with the Oman Power and Water Procurement Company (OPWP) offtaking the plant’s
electricity output during this period.
Generation licences for renewable energy-based projects have previously been awarded to, among
others, the Rural Areas Electricity Company (Tanweer) for its 50 MW wind farm in Harweel and
Amin Renewable Energy Company for its 125 MW solar PV scheme with Petroleum Development
Oman (PDO) as the offtaker.
Also known as Ibri-2 PV Independent Power Project (IPP), the giant scheme is nearing completion
on a 1300-hectare site near Ibri. When fully operational, it will feature an estimated 1.4 million
bifacial-type solar panels, which generate energy from both top and rear sides.

With cutting-edge, N-type panels supplied by leading Chinese manufacturers, the Ibri venture will
be the largest bifacial-based solar PV project to date in the Middle East, according to experts.
Equity partners in Shams Ad-Dhahira Generating Company also include Gulf Investment
Corporation of Kuwait and Alternative Energy Projects Company.
The consortium of PowerChina, one of the world’s largest power construction contractors and
PowerChina Huadong, is building the Ibri-2 IPP as Engineering-Procurement-Construction (EPC)
contractors.
The First National Operation and Maintenance Company (NOMAC) has been named the Operations
& Maintenance contractor.
According to a construction timeline provided by Shams Ad-Dhahira Generating Company, a start-
up test is scheduled later next month with the Commercial Operation Date scheduled for June 1,
2021.
While Ibri-2 IPP will be the largest of its kind to date, it will be surpassed in capacity when Oman’s
next solar PV-based Independent Power Project — a 1,000 MW capacity scheme envisioned in two
individual schemes o f 500 MW apiece — is implemented in the Wilayat of Manah.
Also the capacity adequacy study analyzed the impact of the renewable energy on the generation
expansion plan. A scenario of development of renewable was considered with a target of 15% of
renewable capacity by 2030. This capacity is distributed among CSP, PV and wind and reaches a
total of 3 GW by 2030 as shown in Figure .

Saudi Oil Giant the bigger the operations the bigger is the
Carbon Footprint …. Bloomberg + NewBase
Saudi Aramco's Ras Tanura oil refinery and terminal. Many refineries operated by the world’s
biggest oil company have been excluded from its disclosure of greenhouse emissions.
Before it launched the world’s biggest public listing, Saudi Arabian Oil Co. promised potential
investors a small piece of a trillion-dollar company with access to unrivaled oil reserves. Not just in
sheer volume but in climate friendliness, too.
Aramco executives emphasized in the run-up to an IPO in 2019 that drilling Saudi oil generates
fewer planet-warming emissions than other producers. “Not because our crude is cleaner than other
crudes globally. It’s because of our standards,” Chief Executive Officer Amin Nasser said at a
roadshow, pledging to do even more to deliver lower-carbon oil. “Even though our numbers are
great, climate change is critical for the world.”

The Saudi oil giant will need to include emissions generated from many of its refineries and
petrochemical plants in its overall carbon disclosures, this is as advised by many energy and green
experts. Including all such facilities might nearly double Aramco’s self-reported carbon footprint,
adding as much as 55 million metric tons of carbon dioxide equivalent to its annual tally—or about
the emissions produced by Portugal.
Such needed data is an extra financial load on budget. who “need to be able to put a price on the
climate risks that they are running in their portfolios,” said Nick Stansbury, head of commodity
research at Legal and General Investment Management, which owns Aramco shares as of the end
of 2020.
In response to questions, Aramco said it will begin disclosing direct emissions from its full global
operations this year. “We have a clear and deliberate path to increase the scope and details of
[emissions] disclosure,” the company said in a statement. It added that current disclosure “reflects
emissions from those assets where Aramco has the accountability and ability to manage and control
emissions.”
Missing Emissions
Aramco’s disclosed direct emissions only account for “wholly owned, in-Kingdom” assets
Source: Aramco, Bloomberg
Note: Only Scope 1 and 2 emissions, in million metric tons of CO2 equivalent
Selective accounting helps burnish the low-carbon claims made on behalf of Saudi oil, which have
become a key part of Aramco’s corporate identity. The company often cites a 2018 study published
in the highly regarded journal Science that shows extracting oil in Saudi Arabia generates the
second-lowest amount of emissions in the world, behind only Denmark.
But crude isn’t much use until it’s refined, and distilling black gunk into gasoline, jet fuel or diesel is
emissions-intensive work. Much of this activity has been left out of company disclosures because
Aramco chooses to report only emissions from facilities it wholly owns that are also located inside
the kingdom. What’s more, Aramco is set to double its refining network’s capacity to handle as much

as 10 million barrels a day by 2030; much of those emissions wouldn’t have been disclosed under
the company’s past reporting practices.
Aramco’s accounting wisdom is made possible because many of its refineries are joint ventures or
overseas, including the U.S., South Korea, Japan, China and Malaysia. To calculate those missing
emissions, Bloomberg Green relied on estimates from refineries in more than 80 countries compiled
in a study published in 2020 in the journal Nature Climate Change. The researchers accounted for
variations in more than 300 different types of crude refined worldwide, with lower and upper
estimates of emissions.
Adjusting these calculations for Aramco’s foreign facilities and its share of joint ventures shows a
range for 2019 emissions between 75 million tons and 113 million tons. That gap reflects the
difficulty in accurately estimating the carbon output of any particular refinery. Aramco declined to
provide more precise figures. “We do not comment on emissions on an asset-by-asset basis,” the
company said in its statement.
The high-end estimate puts Aramco’s direct emissions on par with Exxon Mobil Corp., even though
the U.S. company extracted a third as much oil and refined roughly the same amount in 2019.
Aramco’s operations remain cleaner per barrel of oil produced and refined, just not to the degree
suggested by the company’s disclosures.
The Aramco-owned Motiva refinery in Texas produced of 5.4 million tons of carbon in 2019. These
emissions aren’t included in Aramco’s carbon report for the year.
Most oil majors keep detailed records of both past and projected future emissions of individual
facilities, often far beyond what’s disclosed to investors or regulators. An investigation published in

December by Bloomberg Green revealed that Exxon and its joint venture partners, including
Aramco, appear to build detailed forecasts for the carbon output from new projects.
Among Aramco’s development plans is the expansion of Samref, a refinery run as a joint venture
with Exxon in Saudi Arabia. That expansion is likely to come with an additional 950,000 tons of
annual emissions from 2025, according to internal Exxon documents reviewed by Bloomberg
Green.
Aramco’s 50% stake in the project would mean adding 475,000 tons to its carbon ledger, if the
company accounted for its share of joint projects. (Exxon has said projections in its planning
documents are preliminary and have changed under the strain of the Covid-19 pandemic; Aramco
declined to comment on its future projects.)
In most cases, emissions figures tied to specific facilities aren’t made public unless mandated by
government regulations. The Aramco-owned Motiva refinery in Port Arthur, Texas, for example,
reports annual emissions to the U.S. Environmental Protection Agency. It has a capacity to refine
more than 600,000 barrels per day and produced 5.4 million tons of emissions in 2019. Those
figures weren’t included in the company’s 2019 data, since Motiva is located outside Saudi Arabia.
Far More Refining
Aramco plans to grow its refining network’s capacity to handle 10 million barrels a day of crude oil
Source: Aramco, Bloomberg
Note: All facilities in Saudi Arabia unless noted. Joint ventures included.

There are signs of change reaching inside the world’s biggest oil producing nation. Saudi Arabia’s
stock exchange, where Aramco is listed, has previously announced plans to launch an ESG index,
which filters companies based on environmental, social and governance metrics. The exchange
declined to comment on whether it would introduce a regulatory requirement for Saudi companies
to disclose emissions. The Saudi ministry of energy referred questions to Aramco and declined to
comment.
“We regularly engage with shareholders, particularly around our quarterly results announcements,
and with our fixed-income investors, where we discuss ESG issues, including climate change,” the
company said in a statement. “Aramco started decades ago with investments to minimize the impact
of its operations on the environment.” These include reducing flaring, detecting and fixing methane
leaks and increasing efficient use of energy.
Global investors are pushing oil companies to boost disclosures in order to better gauge climate
risk. After years of resistance, Exxon earlier this month began disclosing Scope 3
emissions produced when customers burn fuel. That leaves Aramco as one of the few large, listed
oil companies that doesn’t disclose customer emissions, which typically account for more than 80%
of a total emissions for fossil-fuel producers. This missing data presents another challenge to
Aramco’s low-carbon claims.
Aramco is also investing in chemicals manufacturing, which turns oil and gas into everyday products
from washing powder to plastic. Converting crude into chemicals is an energy intensive process
much like refining that adds to the emissions burden. All the petrochemical assets that Aramco owns
are joint ventures—so those emissions have been up to now excluded from disclosure.
In Saudi Arabia, meanwhile, Aramco has three chemical plants built with Total SE, Dow Inc., and
Sumitomo Corp. There are also Aramco-backed chemical plants in China and Malaysia. Estimating
emissions from these complexes is more difficult than refineries.
The Sadara chemical plant in Saudi Arabia. Including emissions generated by refineries and
petrochemical plants could as much as double Aramco’s carbon footprint.
Source: Saudi Arabian Oil Co.

Still, these chemical plants are likely producing millions of metric tons of carbon each year that aren’t
recognized in Aramco’s current emissions data. The Sadara chemical plant in Saudi Arabia, a joint
venture between Aramco and Dow, is exceptional for voluntarily reporting emissions of 6.3 million
tons in 2019. Aramco’s 65% equity stake reflects about 4 million tons missing from Aramco’s carbon
tally.
That tally is set to grow as Aramco’s newest acquisition is included. Last year, Aramco bought a
70% stake in the petrochemicals company Saudi Basic Industries Corp. SABIC’s Scope 1 and 2
emissions stood at 55 million tons in 2019, which should add a further 39 million tons to the oil
giant’s carbon tally for 2020.
Becoming a publicly traded company publicly has opened Aramco to greater scrutiny. Even though
98% of the company is still owned by the Saudi government, Aramco is under pressure to catch up
with international standards. “Comparability of emissions data between companies is important,”
said Andrew Grant, head of climate, energy and industry research at Carbon Tracker. “Investors
are very much relying on what companies themselves disclose.”
Aramco “is uniquely positioned as the lowest cost producer globally,” according to the prospectus.
That’s “due to the unique nature of the kingdom’s geological formations, favorable onshore and
shallow water offshore environments in which the company’s reservoirs are located.” An analysis
from the influential consultant Carbon Tracker backed that up, saying the company was probably
going to be “o

NewBase January 23-2021 Khaled Al Awadi
NewBase for discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Oil falls on China's COVID-19 cases, high crude build
Reuters + NewBase
Oil prices settled lower on Friday, weighed down by a build in U.S. crude inventories and worries
that new pandemic restrictions in China will curb fuel demand in the world’s biggest oil importer.
Brent crude futures fell 69 cents to settle at $55.41 a barrel, for a 0.4% change on the week.U.S.
West Texas Intermediate (WTI) crude futures fell 86 cents, or 1.6%, settling at $52.27, nearly
unchanged from the beginning of the week.
Overall U.S. crude inventories surprisingly rose by 4.4 million barrels in the most recent week,
versus expectations for a draw of 1.2 million barrels.
Oil price special
coverage

U.S. energy firms this week added oil and natural gas rigs for a ninth week in a row amid higher
energy prices over the past few months, energy services firm Baker Hughes said on Friday, but the
overall count is still 52% below this time last year.
Recovering fuel demand in China underpinned market gains late last year while the United States
and Europe lagged, but that source of support is fading as a fresh wave of COVID-19 cases has
sparked new restrictions.
Travel on U.S. roads fell 11% in November, a steeper decline over October road use as coronavirus
cases increased, the U.S. Transportation Department said Friday.
“The pandemic seems to continue to expand into a second wave in China, with infections rising by
the day and reaching again different regions such as Shanghai,” said Rystad Energy oil markets
analyst Louise Dickson.
U.S. crude inventory data showed signs of strength in domestic product demand. While U.S. crude
oil stockpiles rose unexpectedly last week, refineries hiked output to their highest capacity usage
since March and demand for gasoline and diesel increased week on week.
“Crude oil exports did fall quite dramatically, which is the main reason for a decent build overall in
crude stocks,” said Tony Headrick, energy market analyst at CHS Hedging.

EIA expects crude oil prices to average near $50/B through 2022
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)
In its January Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA)
expects global demand for petroleum liquids will be greater than global supply in 2021, especially
during the first quarter, leading to inventory draws.
As a result, EIA expects t he price of Brent crude oil to increase from its December 2020 average
of $50 per barrel (b) to an average of $56/b in the first quarter of 2021. The Brent price is then
expected to average between $51/b and $54/b on a quarterly basis through 2022.
EIA expects that growth in crude oil production from members of the Organization of the Petroleum
Exporting Countries (OPEC) and partner countries (OPEC+) will be limited because of a multilateral
agreement to limit production.
Saudi Arabia announced that it would voluntarily cut production by an additional 1.0 million b/d
during February and March. Even with this cut, EIA expects OPEC to produce more oil than it did
last year, forecasting that crude oil production from OPEC will average 27.2 million b/d in 2021, up
from an estimated 25.6 million b/d in 2020.
EIA forecasts that U.S. crude oil production in the Lower 48 states—excluding the Gulf of Mexico—
will decline in the first quarter of 2021 before increasing through the end of 2022. In 2021, EIA
expects crude oil production in this region will average 8.9 million b/d and total U.S. crude oil
production will average 11.1 million b/d, which is less than 2020 production.
EIA expects that responses to the recent rise in COVID-19 cases will continue to limit global oil
demand in the first half of 2021. Based on global macroeconomic forecasts from Oxford Economics,
however, EIA forecasts that global gross domestic product will grow by 5.4% in 2021 and by 4.3%
in 2022, leading to energy consumption growth.

EIA forecasts that global consumption of liquid fuels will average 97.8 million barrels per day (b/d)
in 2021 and 101.1 million b/d in 2022, only slightly less than the 2019 average of 101.2 million b/d.
EIA expects global inventory draws will contribute to forecast rising crude oil prices in the first quarter
of 2021. Despite rising forecast crude oil prices in early 2021, EIA expects upward price pressure
will be limited through the forecast period because of high global oil inventory, surplus crude oil
production capacity, and stock draws decreasing after the first quarter of 2021. EIA forecasts Brent
crude oil prices will average $53/b in both 2021 and 2022.

NewBase Special Coverage
The Energy world – Jan-11- -2021
U.S. Shale Operators concern on spending by shale producers,
as US shale growth to moderate in the medium term
NewBase + RYSTAD ENERGY
Pipeline operator Kinder Morgan Inc on Wednesday raised concerns over the pace of ramp-up in
spending in top U.S. shale basins following a rebound in oil prices after beating Wall Street
estimates for quarterly results.
Oil prices are now hovering around $55 a barrel on vaccine rollouts, and in the week to Jan. 15,
U.S. energy firms added oil and natural gas rigs for an eighth week in a row.
“By our calculations, you’re getting close to a rig level in the Permian that could get you back to flat
volumes to where we were pre-pandemic,” Kim Dang, president at Kinder Morgan said at a post-
earnings call.
“And so it’s not clear how much they would ramp up capex in response to increasing prices,” he
added. While Bakken is off to a good start for the year, Eagle Ford has still been weak, he said.
U.S. oil production peaked at nearly 13 million barrels per day (bpd) in late-2019, but is now around
11 million bpd after the coronavirus-induced lockdowns crushed fuel demand and oil prices.
Kinder Morgan, which transports nearly 40% of the natural gas consumed in the United States, said
natgas shipment volumes rose more than 6% sequentially, while total refined product volumes fell
marginally.
Pipeline companies are seeing a recovery in transport volumes after the pandemic wreaked havoc
on demand and forced operators to slash fees to ensure customers keep using their networks to
move oil, gas and refined products.

Excluding items, Kinder Morgan earned 27 cents per share, versus estimates of 24 cents, according
to Refinitiv IBES data. Revenue also rose sequentially to $3.12 billion, above analysts’ estimates
of $3.05 billion.
US shale growth to moderate in the medium term
Despite a slowdown in production growth during the first quarter of 2019, US shale producers remain
on track to continue to increase output year-on-year, achieving the goals set in the beginning of
2019.
Shale oil and gas production in the United States has been growing steadily over the past years,
and this trend is expected to continue in the medium term with total volumes reaching 28.4 million
barrels of oil equivalent per day (10.8 million bbl/d light oil, 4.8 million bbl/d NGL and 76.6 bcf/d gas)
in 2021.
This article addresses the most recent Rystad Energy’s forecast for US tight oil and gas production
and capital investments with the focus on the key contributing shale plays.
A chart showing the US liquids and gas supply from shale formations and spudded shale wells from
2006 to 2012. Source: UCube from Rystad Energy, July 2019
Figure 1 depicts liquids and gas production and the number of spudded wells from shale formations
in the United States from 2006 to 2023. Total shale output has been rapidly increasing, especially
since 2010, when horizontal drilling has become a widespread trend, leading to improved
economics and productivity of wells.
The abrupt oil price collapse in 2014 and continued low oil price environment prevailing well until
2017 has led to production stagnation in the country and even a 7% oil production decline in 2016.
Yet, overall the shale industry has been very resilient, able to adjust to a depressed price
environment through high grading of acreage and cost and productivity improvements. Last year
total production increased by 25% with light oil volumes growing by 32%. In 2019, a 24% growth in

light oil is anticipated. As a result, liquids and gas production is expected to stand at 23.2 million
boe/d this year with light oil contributing 8.3 million bbl/d.
The impressive performance is projected to be achieved even considering a rather conservative oil
price environment (the majority of shale companies set targets assuming WTI oil price of $50 per
bbl) and increased pressure from shale investors to prioritize returns and cost control over
production expansion.
Looking into the future, shale production is expected to continue to expand, growing by 9% CAGR
in 2020-2023 and averaging 32.2 million boe/d in 2023 (17.9 million bbl/d liquids and 85.4 bcf/d
gas). At the same time, oil volumes are anticipated to increase by 11% CAGR during the same time
period and stand at 12.4 million bbl/d in 2023.
A bar chart showing the year-over-year oil production additions split by top US shale and tight liquids
plays. Source: UCube from Rystad Energy, July 2019
Although light oil production volumes from US shale continue to grow, the expansion is expected to
slow down, with light oil additions declining towards 2023, driven by a flat development in drilling
and completion activity, as shown in Figure.
This year, however, oil additions are projected to stand at 1.62 million bbl/d, consistent with the
volumes added last year. In Permian Midland, oil additions are expected to grow relative to 2018.
Other major plays are expected to see relatively stable or declining additions this year.
The Permian Basin tight oil plays, both on the Delaware and Midland side, show the highest
additions since 2016, while the more mature Bakken and Eagle Ford shale plays show stable
production profiles.

A bar chart showing the year-over-year gas production additions split by top US shale gas plays.
Source: UCube from Rystad Energy, July 2019
Gas production growth from US shale is expected to decrease from 9.6 billion cf/d in 2018 to 7.8
billion cf/d in 2019. Large gas additions witnessed in Marcellus and Utica last year are projected to
decrease substantially in 2019, with total growth for Marcellus and Utica estimated at 2.1 billion cfpd
in 2019, compared to 4.5 billion cf/d added last year.
Similarly, Haynesville Shale growth is expected to slow down next year with an average of 1.1 billion
cf/d added, roughly half the outstanding additions seen over the last two years (2.3 bcf/d on average
per year in 2018 – 2019).
A bar chart showing the total US shale drilling and completion costs by shale play on Billion USD
from 2011 to 2019. Source: UCube from Rystad Energy, July 2019

Figure 4 shows total US shale drilling and completion costs from 2011 to 2023, split by the largest
shale oil and gas plays. Total investments have been increasing by 20% CAGR in 2011-2014,
reaching $162.7 billion at peak in 2014.
Following the oil price fall, shale spending collapsed by 42% in 2015 and another 47% in 2016, as
shale producers adapted to lower oil price environment by reducing activity on non-core acreages
and drilling only the most economic areas.
In 2017, the industry entered a period of recovery and drilling and completion costs increased again
by 74%, driven by activity acceleration in all major plays. In 2018, we witnessed an additional 38%
increase in spending with the total level reaching $120 billion.
Among all shale plays, Permian Delaware exhibited the largest growth in investments last year
standing at an impressive 67%. At the same time, since last year shale investors started to show
more concern about the shale operators’ tendency to overspend, focusing on aggressive growth
instead of improving balance sheets.
Especially given the prevailing unstable oil price environment, the importance of returns and thus
cost discipline has become the priority for the shale industry for the years to come.
Therefore, in 2019 we expect a 6% decline in total drilling and completion costs, as shale companies
strive to show cost control amid healthy production growth. In the next four years, the level of
spending in the US shale industry is projected to remain rather flat growing by 0.7% CAGR with
shale operators aiming to spend within cash flow.
***
US shale production has seen continuous growth since the low in 2016, and is expected to keep
growing in the medium term, albeit at a slower rate. By the end of 2019, light oil supply in the US is
forecasted to reach 9 million bbl/d.
The Permian Basin will be the key contributor to the oil production growth going forward, with stable
volumes expected from the more mature shale plays that were leading the growth prior to the oil
price crash in 2014.
Despite the slowdown in spending seen this year, as companies strive to spend within cash flow,
and the corresponding stable drilling and completion activity trend, total US shale volumes are
expected to reach 32 million boe/d (12.4 million bbl/d light oil) by 2023.

NewBase Energy News 23 January 2021 - Issue No. 1400 call on +971504822502, UAE
The Editor:” Khaled Al Awadi” Your partner in Energy Services
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About: Khaled Malallah Al Awadi,
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ASME member since 1995
Hawk Energy member 2010
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Khaled Al Awadi is a UAE National with over 30 years of experience in the Oil & Gas
sector. Has Mechanical Engineering BSc. & MSc. Degrees from leading U.S.
Universities. 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 the UAE operations base. Khaled is the Founder
of NewBase Energy news articles issues, an international consultant, advisor,
ecopreneur and journalist with expertise in Gas & Oil pipeline Networks, waste
management, waste-to-energy, renewable energy, environment protection and
sustainable development. His geographical areas of focus include Middle East,
Africa and Asia. Khaled has successfully accomplished a wide range of projects in
the areas of Gas & Oil with extensive works on Gas Pipeline Network Facilities &
gas compressor stations. Executed projects in the designing & constructing of gas
pipelines, gas metering & regulating stations and in the engineering of gas/oil supply routes. Has drafted &
finalized many contracts/agreements in products sale, transportation, operation & maintenance agreements.
Along with many MOUs & JVs for organizations & governments authorities. Currently dealing for biomass
energy, biogas, waste-to-energy, recycling and waste management. He has participated in numerous
conferences and workshops as chairman, session chair, keynote speaker and panelist. Khaled is the Editor-
in-Chief of NewBase Energy News and is a professional environmental writer with more than 1400 popular
articles to his credit. He is proactively engaged in creating mass awareness on renewable energy, waste
management and environmental sustainability in different parts of the world. Khaled has become a reference
for many of the Oil & Gas Conferences and for many Energy program broadcasted internationally, via GCC
leading satellite Channels. Khaled can be reached at any time, see contact details above.
NewBase: For discussion or further details on the news above you may contact us on +971504822502, Dubai, UAE
NewBase 2021 K. Al Awadi

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New base energy news 23 january 2021 issue no 1400 senior editor eng- khaled al awadi-compressed

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