New base energy news 09 sep 2018 no 1199 by khaled al awadi-cpdf

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NewBase Energy News 12 September 2018 - Issue No. 1199 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: Ras Al Khaimah set to add 20% renewables to energy mix
The National + NewBase
Ras Al Khaimah, the UAE’s northernmost emirate, aims to generate 20 per cent of its power
requirements from renewables and make 30 per cent energy savings as it plans roll-out of an energy
efficiency programme. The emirate, which is home to several energy-intensive industries will
commence a voluntary adoption of its energy efficiency programme
The new programme, named Barjeel, is designed to “moderate the energy and water consumption
of new constructions by approximately 30 per cent versus the current construction standards, while
improving occupant comfort and reducing environmental impact”, said Munther Mohammed bin
Shekar, director general, RAK Municipality Department.
RAK is a relative newcomer to the clean energy drive in the region, having set up its renewables
and energy efficiency office under a year ago. The UAE, which currently meets 98 per cent of its
power generation needs from gas, targets increasing clean energy use by 50 per cent and improving
energy efficiency by 40 per cent by the middle of the century, deploying a total capacity of 44
gigawatts from renewable sources by 2050.
The Barjeel programme, which is expected to receive
2,000 to 2,500 applications annually, in line with current
volumes of building permits issued in RAK, will kick-off
with voluntary adoptions, Andrea di Gregorio, director of
the newly set up energy efficiency and renewables
office in the RAK Municipality told The National.
An awareness campaign is set to begin in a few months,
with the municipality urging private entities to cut energy
and water wastage, he added. The renewables and
efficiency programme will become mandatory in two
years. Barjeel, which also targets 20 per cent water
savings, will help reduce energy and water bills for residents, Mr bin Shekar said.
While Ras Al Khaimah’s population is about 300,000, small compared with Dubai’s nearly 3 million
residents, the UAE’s fourth-largest emirate is home to highly energy-intensive industries, including
one of the world’s largest ceramic tile manufacturing facilities as well as a sizeable cement industry.
The industrial sector, which accounted for 40 to 45 per cent of the 5.3 Terrawatt hours the emirate
consumed last year, is also set to be a main target of RAK's energy management initiatives.
The emirate currently meets its 20% gas requirements through gas sourced from the Dolphin
pipeline that delivers 2.3 billion cubic feet a day of the fuel to the UAE from Qatar’s North Dome
field, one of the largest in the world. RAK Gas, the emirate’s gas company, is in the middle of a
licensing round as Ras Al Khaimah looks to drive investment to diversify sources of the fuel,
particularly for industrial use.

Saudi Aramco award construction of 2 islands to China Harbour
TradeArabia News Service + NewBase
Saudi Aramco has awarded today (September 11) a contract to China Harbour Engineering Arabia
for the construction of two drilling islands under the company’s Berri Increment Program (BIP).
The objective of the BIP is to produce an additional 250,000 barrels per day of Arabian Light crude
oil from the Berri Oil Field to reach 500,000 barrels per day to maintain Saudi Aramco’s maximum
sustained capacity by early 2023.
A signing ceremony to mark the contract award was held in Dhahran today. Signing on behalf of
Saudi Aramco was its vice president of Project Management, Fahad Al-Helal while China Harbour
Engineering was represented by Wu Yuansheng, general manager of China Harbour Engineering
Arabia.
The Program includes the installation of a new Gas Oil Separation Plant (GOSP) in Abu Ali Island
and additional gas processing facilities at the Khursaniyah Gas Plant (KGP) to process 40,000
barrels per day of hydrocarbon condensate associated with the Berri Crude Increment. Related
pipelines, water injection facilities, onshore drilling sites, drilling islands and offshore facilities are
also included.
Under the contract awarded to China Harbour Engineering, two (2) drilling islands shall be
constructed near shore at the north and south sides of the King Fahad Industrial Port (KFIP)
causeway in Jubail, to support the Berri field production capacity islands.
The two drill sites referred to as Site A and Site B will have an approximate overall area 616,553 sq
m and 263,855 sq m respectively.

Aramco has been developing its 900,000 barrels per day (bpd) heavy crude Manifa
project since 2006 with an anticipated completion date of 2013 after delays this
year had already pushed back the start date from September 2011. In an online
article dated December 3, Aramco listed Manifa project details with the line
“Completion date (projected): 2015.”
Aramco has previously said the Manifa project would compensate for declining
output at other fields, and would not boost Saudi production capacity.
The giant Manifa oilfield expansion and neighbouring Karan gas scheme were put out
to bid when the cost of labour and materials were soaring, and initial estimates for
completion rose to $15bn from $9bn.
Saudi oil output has this year fallen to its lowest in over six years as the kingdom
and Opec curbed output to match slumping demand. Expansion plans and further
oilfield development have also become less urgent.

Oman: Debottlenecking LNG plant to boost Oman LNG’s output
Oman Observer -Conrad Prabhu
Oman LNG, the nation’s gas liquefaction flagship, is weighing a major debottlenecking of its Qalhat
plant – a move that could potentially boost its LNG output by 1.5 million tonnes per year (tpy),
according to a news report published by the Middle East Economic Survey (MEES).
The weekly newsletter, focusing on Middle East Oil & Gas, among other topics, quoted Oman’s
Minister of Oil & Gas, Dr Mohammed bin Hamed al Rumhy (pictured), as stating that a “serious
increase” in majority-government owned Oman LNG’s output is in the
works once the plant is suitably debottlenecked.
Debottlenecking is defined as the process of pinpointing specific areas in
plant equipment or the workflow configuration that limits the flow of
product in any refining or petrochemical plant.
By optimising plant operations, overall capacity can be ramped up, experts say. “There are two
ideas that we have,” the MEES report quoted Dr Al Rumhy as saying. “One is to go to Oman LNG’s
three trains and see if there is any opportunity to debottleneck there. The team is working on it and
there is a small opportunity that we think could be realised before end-2019 to another half-a-million
tons with just some easy fixes.”
“The other idea is to debottleneck using some more serious hardware over two years’ time, so by
2021 we could maybe add another million tons. Overall there is another 1.5mn tons per year to be
realised, hopefully. So that’s the easy one.

Within 18-24 months or maximum 30 months we could have a serious increase in that case,” he
further stated. Oman LNG currently operates three LNG trains with a total nameplate capacity of
10.4 million tons per year.
However, for want of adequate supply of natural gas as feedstock for the plant — gas supply being
prioritised to the power and water sector and other critical end-users — Oman LNG has been
operating at only around 80 per cent (or
thereabouts) of its nameplate capacity
for several years.
Starting from last September, however,
gas supplies to the plant were ramped
up to meet its full capacity following the
successful launch of BP Khazzan’s tight
gas development in central Oman.
The additional supplies of gas also
made possible the signing of a landmark
Sales and Purchase Agreement (SPA)
between Oman LNG and BP Singapore
Pte Ltd.
Under the SPA, which covers a seven-
year period starting from January 2018,
Oman LNG will provide 1.1 million
tonnes per annum of LNG to BP
Singapore — which is equivalent to
approximately 18 LNG cargoes
annually.
In the interview, Dr Al Rumhy —who is also Chairman of Oman LNG’s Board of Directors — voiced
optimism that LNG output from the plant is expected to be better than usual this year as well.
“I think exit production could exceed 10m tonnes.
Especially with strong supplies in December, after summer when more gas is allocated towards
domestic consumption. So December will be a good month to send more gas to Oman LNG,” he
said .
Asked if the recent gas discovery at Mabrouk NE, announced earlier this year by Petroleum
Development Oman (PDO), had changed the ministry’s outlook of gas, Dr Al Rumhy stated: “Oh
yes, of course and we anticipate new projects that will take that gas. Some of the more mature fields
are showing declines, so we need to take new findings into account to replace losses elsewhere.
The gas future looks very promising, which is a nice problem to have.”
However, any gas supplies from Mabrouk NE are unlikely anytime soon, as “it would take at least
3-4 years before they can start to take the gas”, the minister noted.
Earlier this year, Oman LNG announced significant investments in the upgrade of its Qalhat
complex. The company is installing a new power 120 MW power plant to replace an existing gas
turbine plant — a move designed to reduce fuel gas consumption and greenhouse gas emissions.

Egypt: Eni's Zohr field reaches 2 bcfd production target
Source: Eni
Eni has announced that the Zohr field is now producing 2 bcfd, equivalent to approx. 365,000
boed. This outstanding result has been achieved only a few months after the first gas in December
2017 and one year before the schedule of the Plan of Development (PoD).
This level of production was achieved thanks to the start-up of the fifth production unit (T4), backed
by the 8 gas producers and a new 30” x 218 km sealine, commissioned last month and confirms
the program pursued by Eni, its partner, Egyptian Natural Gas Holding Company (EGAS) and their
joint venture company Petrobel aimed to reach a plateau in excess of 2.7 bcfd in 2019.
The latest achievement reinforces the exceptional development path of the Zohr project, one of
Eni’s seven record-breaking projects, which is playing a fundamental role in supporting Egypt’s
independence from LNG imports.
The Zohr field, the largest gas discovery ever made in Egypt and in the Mediterranean Sea with
more than 30 tcf of gas in place, is located within the offshore Shorouk Block(some 190 km north
of Port Said). In the Shorouk Block, Eni holds a 50% stake, Rosneft 30%, BP 10%
and Mubadala Petroleum 10% of the Contractor’s Share (where Eni, Rosneft, BP and
Mubadala Petroleum are collectivity the Contractor).
The project is executed by Petrobel, the Operating Company jointly held by Eni and the state
corporation Egyptian General Petroleum Corporation (EGPC), on behalf
of Petroshorouk, jointly held by Contractor (Eni and its partners) and the state
company Egyptian Natural Gas holding Company (EGAS).
Location of Shorouk Concession and Zohr gas field (Source: Eni)
Eni has been present in Egypt since 1954, where it operates through its subsidiary IEOC. The
company is the Country's leading producer with an equity of some 340,000 barrels of oil equivalent
per day.

Morocco: Sound Energy award of production concession for
Tendrara gas discovery Source:Sound Energy
Sound Energy, the Morocco focussed upstream gas company, has announced the award of
the production concession relating to the Tendrara gas discovery in Eastern Morocco by the
Moroccan Ministry of Energy.
The production concession award covers an area of 133.5 Km2 and follows an application by the
Company and its partners in June 2018. The field development plan underpinning this award
includes:
the drilling, pre first gas, of up to 5 new horizontal development wells, in addition to recompletion of
the existing TE-6 and TE-7 wells.
the construction of a gas
treatment plant and
compression station
("CPF") and a 120 km 20
inch Tendrara Gas
Export Pipeline
("TGEP") connecting the
CPF and the delivery
point to the Gazoduc
Maghreb Europe
pipeline. As already
announced, front end
engineering and design
("FEED") is underway
for both the CPF and
TGEP.
the achievement of first
gas in approximately two
years at an expected
mid case production rate
of around 60 million
standard cubic feet per
day over a minimum period of 10 years during which it is currently estimated, subject to optimisation
of drilling plans, that an additional 10 to 13 wells will be drilled to maintain this production rate.
The Company expects to be in a position to take final investment decision on the Tendrara
development once key development milestones have been secured, including a gas sales
agreement, FEED development capital funding and local regulatory administrative formalities.
On 7 June, 2018, Sound announced that it had signed heads of terms with a consortium comprising
Enagas, Elecnor and Fomento for the FEED and conditional construction and financing of all the
infrastructure required, including the TGEP and CPF under a 'build-own-operate-transfer' structure.
James Parsons, Sound Energy's CEO, commented:
'I am delighted with the award of the first development concession in Eastern Morocco, which is a
critical step in commercialising our gas discovery. The Company continues to make excellent
progress on all fronts, including FEED, the gas sales agreement and ground works at TE-9.'

U.S: Texas Oil PL Permian to Gulf Coast set cost at $2 billion
Reuters + NewBase
Magellan Midstream Partners LP on Wednesday projected it would spend about $2 billion to
construct a proposed crude oil pipeline from the Permian Basin in West Texas to the U.S. Gulf
Coast.
“We have binding commitments that give us very attractive economics. But what we don’t know is
the full demand,” which would dictate the project’s final cost, Michael Mears, Magellan’s chief
executive, said at the Barclays energy conference in New York.
The project cost for the Permian Gulf Coast pipeline will be clear after shippers commit to volume
capacity during the so-called open season, Mears said. The bidding process for additional shipper
commitments will be launched later this week.
Production in the Permian basin, the biggest oil-producing region in the United States, has
outstripped its pipeline transport, sending regional crude prices last month to the lowest levels in six
years.
The 600-mile Permian Gulf Coast pipeline is expected to begin operation in mid-2020. Magellan
and co-investors Energy Transfer Partners LP, MPLX LP and Delek US Holdings Inc will construct
the pipeline.

Magellan said it is also is considering new refined products and crude oil investments in Texas,
including additional pipeline, storage and export capabilities.
The Tulsa-based company expects to spend about $2.5 billion from 2018-20 on construction
projects currently under way, primarily related to refined products, marine storage and the Permian
Gulf Coast project.
A 30-inch diameter pipeline to carry Permian Basin oil supply to the Texas Coast has enough support to move
forward, a quartet led by Energy Transfer Partners LP (ETP) said Tuesday.
The 600-mile Permian-Gulf Coast (PGC)
pipeline is expected to be operational by
mid-2020 with “multiple” origins in West
Texas, including Wink, Crane and
Midland.
ETP already had partnered with Magellan
Midstream Partners LP (MMP) to build the
system, with MPLX LP and Delek US
Holdings Inc. announced as partners on
Tuesday.
ETP offered few details. However, the
system initially is to be designed to
transport Permian oil to its Nederland
terminal southeast of Houston and to
MMP’s East Houston terminal. They each
have access to the Houston Ship Channel.
Ultimately, the four partners may increase the pipe diameter to expand capacity, based on additional commitments
received during an upcoming open season, which is expected to be launched this week.
ETP management indicated during first and second quarter conference calls this year that the PGC initially would
transport up to 600,000 b/d, expandable to 1 million b/d. In addition to transporting Permian oil to Nederland and
the East Houston terminals, the system could provide shipper capacity to ETP’s storage facility and pipeline
header systems, as well as deliveries into Bayou Bridge, which moves oil from Nederland to Lake Charles, LA.
“While no ownership interests were disclosed, ETP commentary that they would ultimately expect to own 25%
likely signals ratable interests,” said Tudor, Pickering, Holt & Co. (TPH) analysts. The project is expected to cost
around $2 billion.
Once in service, the PGC is expected to push total Permian Basin “takeaway and local refining capacity to 6.75
million b/d by mid-2020 in-service, allowing multi-year runway for production growth at the expense of legacy
pipeline earnings and marketing margin,” analysts said.
ETP has its fingers in a bevy of Texas projects designed to move oil from the Permian to the Gulf Coast.
ETP and Satellite Petrochemical USA Corp. earlier this year agreed to form the Orbit joint venture to construct an
ethane export terminal at ETP’s Mont Belvieu natural gas liquids (NGL) facility near Houston. In April ETP
launched an open season to test support to convert an existing NGL pipeline in West Texas to a diesel pipeline
to move product from Hebert to a new terminal in Midland using existing pipelines, including ETP’s Lone Star 12-
inch diameter line.
And in May ETP and Enterprise Product Partners LP formed 50/50 joint venture to resume service on the Old
Ocean natural gas pipeline. The 24-inch diameter pipeline, which originates in Maypearl and extends south 240
miles to Sweeny, near the coast, has an initial design capacity of 160,000 MMBtu/d.
ETP and Enterprise also are expanding their jointly owned 36-inch diameter North Texas pipeline, which would
provide around 160,000 MMBtu/d of additional capacity from West Texas for deliveries into Old Ocean. The North
Texas pipeline expansion is expected to be completed by year’s end.

China’s Fracking Hopes Will Hit the Rocks, It’s all about geology.
Bloomberg - David Fickling
Could China’s oil and gas industry be on the brink of a revolution?
That’s one interpretation of the government’s shakeup of regulations on petroleum production this
month. The introduction of drill-it-or-lose-it rules and a possible extension of subsidies for
unconventional gas output could end up dismembering sprawling industry leader PetroChina Co.
and creating a new sector of independent upstream producers like those that have transformed the
U.S. energy industry over the past decade, according to Laban Yu, a Hong Kong-based analyst at
Jefferies LLC.
That would be great news for Beijing. China overtook the U.S. as the world’s largest importer of
crude last year, a headache for a country that’s long fretted about its dependence on imported raw
materials. It’s hard to believe that would have happened had oil production roughly doubled over
the past decade (as it did in the U.S.) instead of standing still.

Dry Well
While U.S. oil production has surged over the past decade, China's has stood still
Source: BP Statistical Review
The question is whether radical change is a realistic prospect. After all, China’s oil and gas
companies have hardly been sitting passively on their land holdings. About 64 percent of
PetroChina’s net acreage was under development at the end of 2017, making it look more like an
entrepreneurial wildcatter than the likes of Total SA, BP Plc and Exxon Mobil Corp., which typically
have wells drilled on 10 percent or less of their leases.
Pump Priming
PetroChina is no slouch in turning its undeveloped acreage into developed oilfields
Source: Bloomberg, Bloomberg Opinion calculations

Nor has it been left behind by the revolution in unconventional oil and gas. Indeed, almost half the
wells that PetroChina drills each year are in the Changqing field, an area near the Mongolian border
characterized by impermeable rock, horizontal bore holes and all the usual features of the fracking
revolution.
Come the Revolution
Almost half of PetroChina's drilling is in the unconventional Changqing field
Source: Company reports, Bloomberg Opinion calculations
Note: Includes both exploration and development wells.
Why, then, has production failed to take off? The best explanation isn’t that the country’s big three
oil companies are an oligopoly — though they are — but that China’s geology is fundamentally more
difficult than that of North America.
Many prospective fields are buried deep below the surface. To make matters worse, they’re
often riven with seismic faults from the slow collision of continental plates that have built the
Himalayas and the Japanese and Philippine island chains.
It’s in many ways a miracle that China produces any unconventional petroleum at all, and even a
prized asset like Changqing can’t always count on making a profit. PetroChina’s agreement this
week to buy 3.4 million metric tons a year of liquefied natural gas from Qatargas Operating Co. is
in many ways an admission of defeat: If it can’t meet the government’s output targets on its own,
it can at least buy the requisite molecules from a third party.
That’s why the most significant move in terms of China’s domestic production is likely to be the
government’s extension of subsidies and the setting of an ambitious objective to produce 200 billion
cubic meters of natural gas in 2020, well above 2017’s 149 billion cubic meters.
If PetroChina, Cnooc Ltd. and China Petroleum & Chemical Corp., or Sinopec, were more
commercially minded, the result wouldn’t be a boom in output but a slump, as managers sought to
cut back spending to get their returns on capital back to healthy levels north of 10 percent.

Capital Punishment
China's oil companies need returns on invested capital of 10 percent or more to cover their cost of
capital, based on Bloomberg estimates. That's a long way from happening
Source: Bloomberg
A better way of thinking about the negotiations between the Communist Party officials who run the
big three petroleum companies and their fellow members in the State Council is that the former
have promised to do their utmost to hit the government’s production targets, and in return want to
see some generous subsidies to make the efforts less ruinously costly than they already are.
That may mean a decent chance of hitting those production goals — something that China badly
needs if it wants to brighten its winter skies with a shift from coal-fired to gas-fired power. But if it
happens, it will be the opposite of a commercial outcome. Unconventional gas hasn’t failed in the
People’s Republic because of lazy state behemoths, but because of intractable geological
challenges. China is the future of fracking — and it always will be.

NewBase September 12 - 2018 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices rise on declining U.S. crude stockpiles, looming Iran sanctions
Reuters + Bloomber g + NewBase
Oil prices rose on Wednesday following a report of declines in U.S. crude inventories and as looming
sanctions against Iran raised expectations of tightening supply, while top producer Russia warned
of a fragile global crude market.
U.S. West Texas Intermediate (WTI) crude futures CLc1 were at $69.84 per barrel at 0428 GMT,
up 59 cents, or 0.9 percent, from their last settlement. WTI futures gained 2.5 percent in the previous
session.
Brent crude futures LCOc1 climbed 28 cents, or 0.4 percent, to $79.34 a barrel. Brent has climbed
for four straight sessions, gaining 2.2 percent the previous day. “Oil prices jumped overnight as
American Petroleum Institute inventory data showed a large drawdown in inventories,” said William
O’Loughlin, investment analyst at Australia’s Rivkin Securities.
Oil price special
coverage

U.S. crude stocks fell by 8.6 million barrels in the week to Sept. 7 to 395.9 million barrels, the
American Petroleum Institute (API), a private industry group, said on Tuesday. Official weekly
government data will be published by the U.S. Energy Information Administration (EIA) on
Wednesday.
Regarding crude oil production, the EIA said on Tuesday it expected U.S. output to rise by 840,000
barrels per day (bpd)between 2018 and 2019 to 11.5 million bpd, lower than a rise of 1.02 million
bpd to 11.7 million that was previously forecast.
Outside the United States, traders have been focusing on the impact of U.S. sanctions against Iran
that will target oil exports from November.
Washington has put pressure on other governments to also cut imports, and many countries and
companies are already falling in line and reducing purchases, triggering expectations of a tighter
market.
“FRAGILE” MARKET
Russian energy minister Alexander Novak on Wednesday warned of the impact of U.S. sanctions
against Iran.
“This is huge uncertainty on the market – how the countries, which buy almost 2 million barrels per
day of Iranian oil will act. The situation should be closely watched, the right decisions should be
taken,” he said.
Novak said global oil markets were “fragile” due to geopolitical risk and supply disruptions. “It is
related to the fact that not all the countries have managed to restore their market and production,”
he said, referring to outages and falling production in Mexico and Venezuela.

Should markets overheat and prices spike, however, Novak said Russia could boost its
output.“Russia has potential to raise production by 300,000 barrels (per day) mid-term, in addition
to the level of October 2016,” he said.
That month Russia produced 11.247 million bpd, a post-Soviet Union record-high. Oil markets were
also eyeing Hurricane Florence offshore the United States amid surging demand for gasoline and
diesel.
The storm is expected to make landfall on the U.S. East Coast on Friday, and has caused fuel
shortages as millions of households and businesses have evacuated. Front-month gasoline futures
RBV8 rose 0.5 percent on Wednesday, while heating oil futures HOV8 increased 0.4 percent.
ETI Prices Steadies as Storm Headed for U.S. Seen Lifting Fuel Prices
Oil held near $68 a barrel after four days of losses, as speculation swirled over whether a giant
hurricane approaching the U.S. East Coast would disrupt supplies and drive up fuel prices.
Futures in New York were little changed after slipping 3.3 percent in the past four sessions.
While Hurricane Florence is likely to miss refineries in the Gulf Coast and Philadelphia areas, it
could affect the Colonial Pipeline, the main conduit for moving gasoline and diesel from Houston to
New York. Drivers may also fuel up before the storm, which could also potentially shut distribution
terminals in the mid-Atlantic.
Tuesday’s relief for crude follows its longest losing streak since May as investors weighed a potential
output increase from Saudi Arabia and Russia against the risk that U.S. sanctions on Iran’s oil
exports will lead to a supply crunch. Meanwhile, President Donald Trump’s unbending stance
against China on trade is raising concerns that tensions between the nations will jeopardize global
economic growth and hurt energy demand.
“The industry is focusing on Hurricane Florence, and while there are no refineries in the path of the
storm, the Colonial Pipeline is prepping for possible power disruptions,” said Stephen Innes,

NewBase Special Coverage
News Agencies News Release 12 September 16-2018
Big Oil Faces ‘Monumental’ Costs to Reach Climate Goals,
JPMorgan + Kelly Gilblom
Europe’s largest oil companies must roughly double the amount of money they’re now dedicating
to “new energies” by the end of the decade to meet key climate targets, according to a report
from JPMorgan Chase & Co. that suggests the challenge facing the fossil fuel industry has been
vastly underestimated.
In some cases, to achieve emission reduction goals, or protect their portfolios against future declines
in oil demand, companies such as Total SAwill have to raise their overall capital expenditure
budgets. If the sector does double what it dedicates to clean fuels by 2020, it will still need to double
it again within five years, or risk losing credibility in discussions about climate change.
Using a model built on public statements from the eight largest European oil companies and industry
“best practices”, the report paints a picture of a sector not fully prepared for a rapidly approaching,
and enormous change. Spending more on clean fuels will help in climate discussions, but could
cause them to miss oil and gas production targets or return less cash to shareholders that expect a
rebound in crude prices to fatten their pockets.

“We’re not really bracing ourselves enough,” said Chrystian Malek, head of European, Middle East
and African oil and gas research at JPMorgan, in an interview. “If they’re really going to lower their
carbon footprint, the dollars that they have to spend are monumental.”
Malek said he created the report partly to “hold their feet to the fire”. Oil companies have stated
goals related to cutting their own operational emissions, reducing flaring and shifting their portfolios
so the products they sell emit fewer greenhouse gases. JPMorgan cataloged those targets while
adding in its own forecasts for upcoming emissions rules globally to determine how much companies
should spend.
The largest European oil companies spend about 5 percent of their capital expenditure budgets on
“new energies” -- low carbon energy fuels and systems. That needs to rise to 9 percent by 2020
and then 17 percent by 2025, according to the analysis. The largest company in the study, Royal
Dutch Shell Plc, will more than double its spending on clean fuels in 2025 to $4.5 billion a year.
That’s up from $1 billion to $2 billion now, the report said.
For some companies, such as Shell, that’s affordable. The Anglo-Dutch oil major will have a $27
billion capital expenditure budget for all energy in 2025, and can afford to reduce what it dedicates
to traditional fossil fuels in favor of low-carbon investments. Spain’s Repsol SA, which already
dedicates 15 percent of its capital expenditure budget to new energies, and Norway’s Equinor
ASA are also relatively well-placed to face the change.
Production Targets
Other companies, such as Total, aren’t able to spend less on oil and gas without missing production
growth targets. The French oil major will have to roughly quintuple new energy spending to $2.8
billion by 2025, but can’t afford to cut its spending on traditional fuels. It will need to raise total
spending in order to keep all its promises, which could hurt shareholder returns.
Both Total and Shell declined to comment.
The scope of the challenge -- and the difficulty of quantifying it -- may factor into why shares of the
largest oil companies haven’t rebounded along with a surge in crude prices. The Stoxx Europe 600
Oil & Price Index is up 7.5 percent so far this year versus a 17 percent rise in Brent crude.

The industry is set to deliver record cash flows, can meet its production targets within its existing
capital framework and has kept a tight leash on spending. But the chorus of critics arguing against
fossil fuel use is growing stronger, which means it’s unlikely the biggest oil companies will still be
able to acknowledge climate change without dedicating enough capital to address it, Malek said.
“They could kick the can down the road; they could all possibly do that,” said Malek. But “customers
are breathing down their necks, and when they’re walking to investor meetings, I think it’s now a
real problem.”

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
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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 September 2018 K. Al Awadi

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