Mubadala to invest $50m in US LNG project

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NewBase Energy News 27 October 2019 - Issue No. 1289 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 Mubadala to invest $50m in USA Rio Grande LNG project
The National
Mubadala reached an agreement with NextDecade Corporation to invest $50 million (Dh183.7m) in
the US company's upcoming Rio Grande liquefied natural gas facility, as part of the Abu Dhabi
entity's plans to capture gains from the shale boom.
Mubadala will purchase the equivalent amount in common stock via a private placement at a price
of $6.27 per share, the company said in a statement.
The 27 million tonne per annum Rio Grande LNG project is one of the largest gas schemes under
way in the US, which has experienced a boom in production along its shale basins due to greater
efficiencies in drilling. The Rio Grande project in Texas will source gas from the Permian Basin
before liquefying it for the global export markets.
The scheme was "optimally positioned to provide a highly competitive export route for the abundant
gas resources of the Permian Basin and a compelling commercial proposition for LNG customers,
Permian producers and NextDecade shareholders alike", Mubadala midstream executive director
Khalifa Al Romaithi said.
"Our investment also reflects Mubadala’s positive outlook on the global gas market and the growing
role of gas in the energy transition," he added.
www.linkedin.com/in/khaled-al-awadi-38b995b

Mubadala will have one seat on NextDecade's board of directors and will have the right to contribute
a certain amount of project-level capital injection in Rio Grande's final investment decision.
NextDecade plans to reach financial close on the project by the first quarter of 2020, with
commercial operations expected to begin in 2023. US contractor Bechtel was awarded two
contracts worth $9.56 billion earlier this year to execute the engineering, procurement, and
construction of the project.
Rio Grande is the latest foray into the US gas sector for Mubadala, which has looked to position
itself as a strong player in the North American natural gas market, as well as the petrochemicals
industry.
Last year, Mubadala subsidiaries Nova Chemicals and Borealis signed a definitive agreement with
France’s Total to develop a $1.7bn petchems facility in Texas.
About NextDecade Corporation
NextDecade is a liquefied natural gas (LNG) development company focused on LNG export projects
and associated pipelines in Texas. NextDecade intends to develop the largest LNG export solution
linking Permian Basin associated gas to the global LNG market, creating value for producers,
customers, and stockholders.
Its portfolio of LNG projects includes the 27 mtpa Rio Grande LNG export facility in Brownsville,
Texas and the 4.5 Bcf/d Rio Bravo Pipeline that would transport natural gas from the Agua Dulce
area to Rio Grande LNG. NextDecade’s common stock is listed on the Nasdaq Stock Market under
the symbol “NEXT.” NextDecade is headquartered in Houston, Texas. For more information, visit
www.next-decade.com.
About Mubadala
Mubadala Investment Company is a sovereign investor managing a global portfolio, aimed at
generating sustainable financial returns for its shareholder, the Government of Abu Dhabi.
Mubadala’s US$229 billion portfolio spans five continents with interests in multiple sectors including
aerospace, ICT, semiconductors, metals and mining, renewable energy, oil and gas,
petrochemicals, utilities, healthcare, real estate, pharmaceuticals and medical technology,
agribusiness and a global portfolio of financial holdings across all asset classes. Mubadala has
offices in Rio de Janeiro, Moscow, New York and San Francisco, with a joint venture in Hong Kong.
Mubadala is a trusted partner, an engaged shareholder and a responsible global company that is
committed to world-class standards of governance.

UAE:Huawei, Phanes join hands to develop 25MW solar project
TradeArabia News Service
Phanes Group, a global end-to-end solar provider based in Dubai, said it has partnered with leading
ICT solutions provider Huawei to deliver the first medium voltage (MV) rooftop connection solar
project in the UAE.
The 25.8 MW distributed rooftop
project was developed for DP World -
the second largest port operator
worldwide. This is currently the largest
distributed development in the UAE
and has a unique composition of
different project types, including
warehouses, carports, and
commercial buildings, said a
statement from Phanes Group.
The development includes 88,000 plus
solar panels, Huawei's SUN2000-(8-
40) KTL all series Smart String
Inverters, 25 independent projects,
each with single Points of Connection
(POC), across 60 plus rooftops and 6 different roof types including the region's first biggest single-
site rooftop (2.6 MW).
The project also had 12 different building profiles and included simultaneous work on up to 12
projects, it stated. It is a key project under Dubai's Shams net-metering scheme and serves as a
blueprint for the roll-out of distributed industrial solar PV for the region.
Stefanos Lialios, the head of project execution for Oryx Solar Systems Solutions, a Phanes Group
company, said that the project provides stable power generation to DP World thanks to the
performance of the Huawei smart string inverters, especially their reliability and low failure rate since
they were commissioned to the grid.
Phanes Group said it supports the use of the natural cooling smart string inverters in extremely high
temperatures and desert conditions, and further optimizes costs through the smart management
system.
The DP World Solar project takes advantage of the high natural irradiance to produce 35,734 MWh
electricity annually and displaces more than 21,000 tons of CO2 every year. It is accredited under
the UN Component Project Activities for Small-Scale Solar in UAE and contributes to Dubai's
Integrated Energy Strategy 2030 as well as the UAE's vision 2021 for a stainable environment, said
the statement from Phanes Group .
It will continue working together with Huawei to develop more efficient solar PV plants worldwide, it
added. Established in 2012, Phanes Group is an international solar energy developer, investment
and asset manager, strategically headquartered in Dubai, UAE.

Kazakhstan’s Oil Production Is Surging Despite Pledges to Cut
Bloomberg (By Julian Lee and Olivia Konotey-Ahulu ) + NewBase
Kazakhstan’s oil production is setting new daily records after maintenance works were completed
at the country’s three big oil fields. Barring unforeseen issues, the Central Asian nation’s output
looks set to stay well above its OPEC+ quota under an output deal that runs to the end of March.
Daily production hit an all-time high of 269,000 tons on Thursday. When converted to barrels, the
volume is far in excess of what the nation pledged it would pump to help OPEC and allied oil
producers avert a global glut.

Indonesia: Coro Energy , Tambak-2 operational update
Source: Coro Energy
Coro Energy, the Southeast Asian focused upstream oil and gas company, has provided an
operational update in relation to the drilling campaign in the Conrad Petroleum-operated Duyung
Production Sharing Contract in the West Natuna basin, offshore Indonesia, in which Coro holds a
15% interest.
Following the drilling of the Tambak-2 well as announced on 15 October 2019, operations have
been focussed on conducting a Drill Stem Test ("DST") across the intra-Muda reservoir. The
operator has reported that these DST efforts have not been successful, due to formation damage
in this highly permeable and porous reservoir.
 Two separate DST attempts have been conducted across the intra-Muda reservoir without
success due to extreme formation damage.
 Operational issues encountered while setting the bridge plug (needed to isolate the gas-
bearing reservoir) resulted in a 'swabbing' of the well which led to a substantial gas kick, with
gas flowing to surface.
 Heavy mud was used to control the well, resulting in large volumes of barite mud being lost
to the permeable reservoir.
 Reservoir formation became plugged and damaged by the barite mud.
Prior to the DST attempts, a full logging suite was acquired, including formation pressure
measurements, in the Tambak-2 well. This confirms a 10 metre (33 ft) gross gas zone with formation
permeabilities calculated to be in the 200 millidarcy to 3 darcy range across the best quality zone,
a highly permeable reservoir as predicted. The pressures indicate the well encountered the same
gas accumulation as at Mako South-1, over 13 km away, with mud gas readings indicating a dry
methane gas almost wholly C1 with minor C2, again consistent with Mako South-1. Petrophysical

analysis of the log data suggests any DST testing would have yielded similar high flow rates to the
discovery well.
The next step in the drilling campaign will be to mobilise the rig to the Tambak-1 location where the
well spud is anticipated in the coming days.
The JV partners in the Duyung PSC are: Conrad Petroleum (Operator) 76.5%; Coro
Enegy 15%; Empyrean Energy 8.5%.
James Menzies, Coro Energy CEO commented:
'While the lack of a successful DST at Tambak-2 is disappointing, the main objectives of the well
have been met, namely demonstrating a continuous gas-bearing reservoir over a large distance;
confirming the same pressure system and gas-water contact as seen at Mako South-1 and in
addition, the same quality of reservoir but with better sand development than expected. In light of
these results, we remain confident of a material uplift in contingent resources and asset value.
The Asian Endeavour 1 rig is now being prepared to mobilise to the Tambak-1 location where we
will further appraise the Mako field and also test the underlying Tambak structure, an exciting
amplitude supported prospect with mid-case prospective resource potential of 250 Bcf.'

Morocco: SDX Energy commences drilling operations
Source: SDX Energy
SDX Energy has announced the commencement of a 12 well drilling campaign, targeting a
mean 15bcf of gross unrisked prospective resources, in its operated Gharb Basin (SDX: 75%
working interest) acreage in Morocco.
The first seven wells located in the Company's core producing concessions at Sebou and Gharb
Centre are lower-risk appraisal wells targeting prospects which are close to existing infrastructure.
These wells can be tied in quickly, at low cost, and are similar in geological risk to the discoveries
already made and producing in this area.
These seven appraisal wells will be followed by two step-out exploration wells further to the north in
Gharb Centre and outside the reach of the Company's existing infrastructure. These two exploration
wells are targeting prospects which are similar to the discoveries made in Sebou and Gharb Centre
albeit they are deemed higher risk as this part of the concession has not been previously
tested. Success here could open up this northern area of the concession for extensive follow-on
drilling.
The last three wells of the campaign are expected to be higher-risk exploration wells in the Lalla
Mimouna Nord concession, targeting larger prospects in deeper, as yet unproven, horizons.
In order to optimise operations and reduce costs, SDX has secured an advanced North American
rig to reduce drilling time. Furthermore, the Company will perforate and test successful wells in
separate campaigns, with multiple wells tested back to back in each campaign to reduce equipment
mobilisation costs. The drilling campaign is expected to complete in Q1 2020.
SDX will update the market on the progress of the drilling campaign at the earlier of the completion
of the first testing campaign, which will cover up to four of the first seven appraisal wells, or the
issuance of the Company's planned year end operational update in early January 2020.
Mark Reid, CFO and Interim CEO of SDX, commented:
'SDX is pleased to announce the start of its drilling campaign in Morocco. The 12 wells have three
key objectives. The first objective is to drill seven lower risk wells in our existing core producing
area. These wells are close to existing infrastructure and will increase reserves for the continued
supply of gas to our existing customers.
Our second objective is to drill two
step-out exploration wells to the north
of our core production area which, if
successful, would open up new,
target-rich acreage for future
drilling. The final objective of the
campaign is to test larger but higher-
risk prospects in the Lalla Mimouna
Nord concession. To do this, we plan
to drill up to three wells, however, if
the first well does not meet our
expectations, we may move the rig
back to our core

Nigeria: Eni starts production at Obiafu 41 in Nigeria
Source: Eni
Eni has started gas and condensate production from the Obiafu 41 discovery, Niger Delta, just 3
weeks after well completion. The discovery contains approx. 28 billion cubic meters of gas and 60
million barrels of condensate, and the gas from the discovery will largely be channelled to the
domestic market in order to feed the power sector.
This record time-to-market was made possible thanks to Eni's new integrated model, under which
the various disciplines work in parallel from the exploration phase, and all synergies with existing
production facilities are properly leveraged. At the end of ramp-up, production will reach a capacity
of about 3 million cubic meters of gas and 3,000 barrels of condensate per day.
The gas from this discovery will be processed at the Eni-operated Ob-Ob plant, and then sent to
the Okpai Power Plant, also operated by Eni. Okpai is Nigeria’s first independent power plant and
one of the most efficient ones in the country.
It currently has an installed capacity of 500 MW and an upgrade is underway which will double its
capacity to 1 GW. Once the upgrade is completed, Eni will generate 20% of the entire national
electricity production, establishing itself as the leading electricity producer in the country.
In Nigeria, approx. 30% of Eni’s gas production is supplied to the domestic market, a sign of the
company's focus on the environmental and economic impact of its business on local communities.
Eni's commitment in this regard is also evidenced by ongoing projects aimed at reducing gas flaring.
The sale of gas, that previously would have been flared, to local companies is a contribution to the
development of the domestic gas market as well as a boost to the local economy as a whole.

Through this multi-pronged flaring down strategy Eni aims at zeroing flared gas from all its
operations by 2025.
In addition to Okpai power plant, Eni supplies power from its facilities to 85 local communities with
approx. 500,000 people. Nigeria’s needs are at the core of Eni's strategy, since it began operations
in the country in 1962, with projects focusing on access to energy, social and agricultural
development, education and training, healthcare, environmental protection and culture.
In the last 10 years alone, more than 1,000 sustainability projects have been completed, and over
400 km of roads and 150 schools and hospitals have been built, contributing significantly to
improving the quality of life of the communities in which Eni operates.
Among the company’s most impactful projects is the Green River Project (GRP), an integrated
program of agricultural entrepreneurial development, created to promote a path of autonomous
development in the Niger delta. Over 32 years, the GRP has benefited over 120 communities
reaching over 500,000 people across the states of Bayelsa, Delta, Rivers and Imo.
Eni has been present in Nigeria since 1962, with operated and non-operated exploration,
development and production activities on 30,049 sq kms in the onshore and offshore areas of the
Niger Delta. In 2018, Eni's equity hydrocarbon production amounted to 100,000 boe/day.

Indian diesel exports Up as demand low from a slowing economy
Bloomberg + NewBase
Economic growth has almost halved since the middle of 2016, India’s spluttering economy is turning
the energy-hungry nation into an unlikely source of diesel exports.
The industrial fuel is the lifeblood of Indian manufacturing, transport, and agriculture, making it the
country’s most-consumed petroleum product. But five straight quarters of slowing growth is taking
an increasing toll on demand, resulting in diesel consumption slumping to the lowest since the start
of 2017.
The sharp slowdown - economic growth has almost halved since the middle of 2016 -- was
compounded by a heavier-than-normal monsoon in some areas, taking refiners by surprise. That
forced them to cut operating rates and spurred a 47 per cent jump in exports of diesel, also known
as gasoil, to a record 3.5 million tonnes last month.
“We do see India’s gasoil demand dipping in the near term in line with the weak macroeconomic
environment,” said Rachel Yew, an analyst at industry consultant FGE in Singapore. The weakness
will continue “at least through the rest of 2019,” she said.
Indian diesel consumption has fallen for four straight months to 5.8 million tonnes in September
from 7.8 million tonnes in May, according to government data. The 3.5 million tonnes of overseas
shipments last month compares with an average of 2.2 million tonnes in the first eight months of the
year.
While Indian diesel exports typically go to Europe, strong near-term buying interest from Asia may
draw some shipments east, said Nevyn Nah, an analyst at Energy Aspects. Exports are likely to
taper toward the end of the year, although they will remain higher than the same period in 2018, he
said.

Mangalore Refinery & Petrochemicals has offered 650,000 tonnes of diesel for loading in October
and November, according to data compiled by Bloomberg, two-thirds more than for the previous
two months. The refiner is offering more diesel via tenders because it boosted run rates to make up
for forced shutdowns earlier this year due to a landslide and water shortage, said a company official,
who asked not to be identified because of internal policy.
Indian Oil Corporation, the country’s biggest refiner, has offered as much as 130,000 tonnes of
October-loading diesel loading in October. The state-owned company, which is usually an importer
of gasoil, had to shut units in at least two refineries in September due to the lower demand, the oil
ministry said in a statement this week.
“The recent surge in India’s diesel exports appear to have been a product of sluggish domestic
demand and refiners seeking solace in the export markets,” said Peter Lee, an analyst at Fitch
Solutions in Singapore. Favorable diesel markets in Europe and North America have also
encouraged the shipments, he said.
Out of 23 refineries operating in India, 18 are owned by state-run companies; three are in the private
sector; and two are joint ventures, according to a report by the consultant Pricewaterhouse Coopers.
“The growth in refining capacity has transformed India from a net importer of petroleum products
until 2000 to 2001, to one of the world’s largest exporters of refined petroleum products in 2014 to
2015,” PwC says.
But production of crude oil within India is very limited, which means the country is heavily dependent
on imports – and this dependency is growing. “The indigenous production of crude oil in India is not
keeping pace with the increased refining capacity,” PwC says. “The challenge before Indian
companies is to take effective measures for enhancing the exploration and production of petroleum
resources. Simultaneously, the infrastructure for refining, distribution and marketing, import, export
and conservation of petroleum products must be improved.”

U.S. petroleum product exports rose slightly in the 1st-H of 2019
Source: U.S. Energy Information Administration, Petroleum Supply Monthly
In the first half of 2019, the United States exported an average of 5.47 million barrels per day (b/d)
of petroleum products, an increase of 19,000 b/d (0.3%) from the first half of 2018 and the slowest
year-over-year growth rate for any half year in 13 years.
Two factors that likely contributed to lower exports were lower U.S. refinery runs in the first half of
2019 compared with the first half of 2018 and slowing global economic growth, which is limiting
demand for petroleum products. In the first half of 2019, increased exports of propane and distillate
offset decreased exports of all other petroleum products.
Distillate remained the largest U.S. petroleum product export in the first half of 2019, averaging 1.3
million b/d, an increase of 60,000 b/d (5%)
compared with the first half of 2018.
Distillate has many uses, including
transportation, manufacturing, agriculture,
residential, and commercial activities.
Mexico was the largest destination for U.S.
distillate exports during the first half of
2019, receiving 290,000 b/d, or 22% of
total U.S. distillate exports. Aside from
Mexico, U.S. distillate exports go mostly to
Central and South America, including
Brazil (13%), Chile (7%), and Peru (5%).
U.S. distillate exports also go to Europe,
mostly to the Netherlands (4%), which is
a transshipment country for some of the
U.S. distillate volumes.

Propane was the second-largest U.S. petroleum product export in the first half of 2019, at 1.03
million b/d, an increase of 142,000 b/d (16%) from the first half of 2018. Propane is used as a space
heating and transportation fuel and as a petrochemical feedstock. Most U.S. exports of propane
are destined for use as a petrochemical feedstock, mainly at facilities in Asia and Europe.
U.S. residual fuel exports declined the most between the first half of 2019 and the first half of 2018,
falling by 74,000 b/d to average 258,000 b/d. In the first half of 2018, Singapore was the top
destination for U.S. residual fuel exports, most likely to supply Singapore’s marine bunkering
market.
However, in the first half of 2019, trade press reported that Singapore’s bunker market was
preparing for new international regulations that limit the sulfur content of marine fuels by drawing
down higher sulfur residual inventories to make room for inventories that are lower in sulfur. As a
result, average U.S. exports of residual fuel oil to Singapore decreased 68,000 b/d (80%) in the first
half of 2019 compared with the first half of 2018.
EIA forecasts that continued growth in petroleum product exports, albeit slower than in previous
years, combined with increasing U.S. crude oil exports, will result in the United States becoming a
total petroleum net exporter. The U.S. Energy Information Administration’s (EIA) October
2019 Short-Term Energy Outlook forecasts this change to occur in the fourth quarter of 2019.

NewBase October 27 – 2019 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices clock strong weekly gains on trade hopes, crude supply
Reuters - Laila Kearney + NewBase
Oil prices rose on Friday, registering the strongest weekly gains in more than a month as support
from optimism over a U.S.-China trade deal, falling U.S. crude stocks and possible action from
OPEC to extend output cuts outweighed broader economic concerns.
West Texas Intermediate (WTI) crude futures settled 43 cents, or 0.8%, higher at $56.66 a barrel,
clocking a weekly rise of more than 5%, its strongest since June 21. Brent crude ended 35 cents,
or 0.6%, higher at $62.02 a barrel, logging a weekly gain of more than 4%, its best since Sept. 20.
Oil price special
coverage

Oil got a boost from signs of progress in talks on resolving the U.S.-China trade dispute that has
weighed on crude demand. Washington officials on Friday said the United States and China were
close to finalizing the first part of a trade deal after months of a tariff war.
“Some of the vibes out of the U.S.-China talks are positive again and that’s certainly what’s fuelling
the stock market, so oil is benefiting from it,” said John Kilduff, a partner at Again Capital LLC in
New York.
Wall Street, which oil prices often follow, approached a record high after the trade comments from
Washington.
The weekly performance was underpinned by the surprise drop in U.S. inventories, with crude
stocks falling by about 1.7 million barrels last week.

“We’re holding our ground after a pretty good up week with the surprise draw in inventories this
week,” said Phil Flynn, senior energy analyst at Price Futures Group. Yet concerns over weakening
economic growth continued to drag on prices.
“Slowing global activity will see demand drop, so the reality is that oil rallies will be limited,” said
Jeffrey Halley, senior market analyst at OANDA.
Economists in a Reuters poll said a steeper decline in global economic growth remains more likely
than a synchronised recovery, even as multiple central banks dole out rounds of monetary easing.
Providing further price support this week, officials at the Organization of the Petroleum Exporting
Countries said extended supply curbs are an option to offset the weaker demand outlook in 2020.
Saudi Arabia, OPEC’s de facto leader, wants to focus first on boosting adherence to the group’s
production-reduction pact with Russia and other non-members, an alliance known as OPEC+,
before committing to more cuts, sources told Reuters. The alliance in July renewed the pact to cut
output by 1.2 million barrels per day since Jan. 1, until March 2020.
“The energy complex is also deriving some support from slowing in the pace of U.S. crude
production gains,” Jim Ritterbusch, president of Ritterbusch and Associates, said in a note.
In the United States, energy companies reduced the number of oil rigs operating this week, leading
to a record 11-month decline as producers follow through on plans to cut spending on new drilling.
The rig count is seen as an indicator of future output.

NewBase Special Coverage
News Agencies News Release Oct. 27-2019
Italian Gaint Eni Reports Profit Meets Estimates
Bloomberg + Eni
Eni SpA’s third-quarter profit almost matched estimates as higher oil and natural gas production
helped counter a drop in prices. Adjusted net income was 776 million euros ($862 million), compared
with an average analyst estimate of 778.6 million euros in a Bloomberg survey.
Key Insights
The Italian giant opens what should be a broadly weaker third quarter for
Europe’s integrated oil majors, according to Bloomberg Intelligence.
Prices for both gas and oil were lower in the period as a slowing economy
affected demand growth.At Eni, total oil and gas production averaged 1.89
million barrels a day, just exceeding the average analyst estimate of 1.875
million and beating year-earlier output of 1.8 million.
That reflects start-ups and ramp-ups in Egypt, Libya, Ghana, Angola, Mexico and Algeria.The
company remains on track to achieve its forecast of 2%-2.5% annual growth, or 1.88 million barrels
a day.That growth, together with better cash flow, will allow Eni to finance its planned dividend,
forecast at 3.4 billion euros, according to a company statement.
Market Reaction
Eni slipped 0.3% to 14.10 euros at 9:25 a.m. in Milan trading. Brent crude was down by the same
amount.The results show “good growth” in production volumes, Jason Kenney, an analyst at Banco
Santander SA, said in a note. There’s “good reason for confidence in Eni,” Kenney said, reiterating
his buy rating.
Know More
Adjusted net income in the third quarter was lower than the 1.39 billion euros posted a year earlier,
but higher than the second quarter’s 562 million euros.While the production outlook was maintained,
Eni tweaked guidance in downstream, forecasting a refinery break-even margin at around $5.20 a
barrel this year amid an “unfavorable trading environment.”At the budgeted scenario and at full
capacity, the margin would be $3.50 at the end of 2019, it said.To see a more detailed rundown of
Eni’s earnings,
Eni investment case
We concretely support a just energy transition, with the objective of preserving our
planet and promoting an efficient and sustainable access to energy for all. Our work
is based on passion and innovation, on our unique strengths and skills, on the equal
dignity of each person, recognizing diversity as a key value for human development,
on the responsibility, integrity and transparency of our actions. We believe in the value
of long term partnerships with the countries and communities where we operate,
bringing long-lasting prosperity for all.

Eni results for the third quarter and nine months of 2019
“Eni has delivered robust results in the quarter, while also finalizing the acquisition of Exxon’s assets
in Norway and a 20% stake in the Ruwais refinery in the UAE, providing a further boost to growth
and stability.
We achieved significant 6% growth in upstream production in the quarter, mainly from Egypt,
Kazakhstan and Ghana, as well as first production from Mexico, just 11 months after the final
investment decision was made. The growth in production and results from gas sales and oil
marketing allowed us to generate significantly better cash flow of €9.4 billion in the first nine months
of the year, despite an adverse trading environment.
This is sufficient to cover not only the €5.6 billion in net investments during the period, but also the
planned dividend and buy-back for the entire year, forecast at approximately €3.4 billion.
This shows that Eni's efficient portfolio can achieve breakeven at prices well below current difficult
conditions. In particular, in the third quarter Brent prices decreased by 13 $/barrel and European
gas prices fell by over 50%, as the downward trend which began in 2018 gathered pace. From the
end of the year, the acquisition in Norway, adding further production of around 100 thousand barrels
per day, in addition to the stabilizing contribution from our stake in the Ruwais refinery, which will
increase our current refining capacity by 35%, will contribute to the robustness of our results.
Finally, it is important to highlight the continued progress from our complementary businesses of
the future, from bio-refineries to renewables and the first waste to fuel pilot plants, which draw on
in-house research and will become more and more our “second exploration activity” in terms of new
business generation.
On this basis, I am very confident in Eni’s position as I look to the near future as well as to the
medium and long-term transition.”
Highlights
Exploration & Production
Hydrocarbon production
 Strong growth in the third quarter: 1.89 million boe/d, up by 6%, when excluding price and
portfolio effects, the highest ever third quarter (1.85 million boe/d in the nine months, up by
1.8%);
 Further production ramp-up anticipated in the fourth quarter;
 Added 240 kboe/d from start-ups and ramp-ups in the nine-month period, with the bulk
coming from Egypt, Libya, Ghana, Angola, Mexico and Algeria;
 2019 main start-ups:
o Area 1 offshore Mexico, started up in early production in just eleven months after the
FID;
o in Egypt, the Baltim SW gas project in the Great Nooros Area, in just nineteen months
after the FID, and recent near-field oil discoveries in the Melehia SW development
area;
o Trestakk field in Norway and the Berkine oil field in Algeria.

Portfolio
 Vår Energi, the joint venture between Eni (70%) and HitecVision (30%), announced the
acquisition of ExxonMobil’s upstream assets in Norway, which are expected to produce 150
kboe/d in 2019, with a production target in excess of 350 kboe/d by 2023. The consideration
of the transaction amounting to $4.5 billion will be funded by Vår Energi’s own cash flows
and dedicated credit lines. Closing is expected by the end of 2019 with accretive effects on
the net cash flow.
 Signed agreements to divest exploration permits in Kenya, Morocco and Mozambique to Qatar
Petroleum.
 Divested a 20% interest in the Merakes discovery to Neptune.
Exploration
 Main successes:
o in the nine-month period approximately 650 mmboe of exploration equity resources
were discovered;
o in Block 15/06 (Eni operator with a 36.8% interest) offshore Angola, since the
beginning of the year, three discoveries have been made totaling five since the
resumption of exploration in 2018. The cumulative resources found are pegged at 2
billion barrels of oil in place;
o Vietnam: a gas and condensates discovery in the exploration permit Ken Bau, in the
offshore Block 114 (Eni operator with a 50% interest);
o Niger Delta: made a significant near-field discovery, already linked to production
facilities, with a capacity of approximately 3 mmcm/d of gas and 3 kbbl/d of
condensates;
o Offshore Ghana: new gas and condensates discovery made in the CTP-Block 4 (Eni
operator with a 42.47% interest), with estimated resources in place ranging between
550-650 bcf of gas and 18-20 mmbbl of associated condensate, representing a
potential commercial discovery due to its proximity to existing production
infrastructures;
o Norwegian North Sea: new oil and gas discoveries in the PL 869 license participated
by Vår Energi;
o Egypt: a gas discovery in the Nour exploration licence (Eni operator with a 40%
interest). Near-field discoveries in the Western Desert, the Nile Delta and in the Gulf
of Suez which have already been linked to the production facilities.
 Reloading the Eni’s mineral interest portfolio: in 2019, acquired new exploration areas
covering 27,541 square kilometers in Algeria, Bahrain, Cyprus, Egypt, Ivory Coast,
Kazakhstan, Mexico, Mozambique, Norway and the UAE.
 Adjusted operating profit Exploration & Production: €2.14 billion, down by 31% q-o-q; €6.59
billion in the nine months, down by 17%. Excluding the impact of the loss of control over Eni
Norge on the 2018 results to allow a-like-for-like comparison, and net of scenario effects and
IFRS 16 accounting, the adjusted operating profit increased by 12% in the quarter (up by 7%
in the nine months), mainly due to production growth. A large portion of the scenario effects

was driven by significantly lower gas prices, mainly in Europe, which negatively affected the
result for €530 million in the quarter and €690 million in the nine months.
Gas & Power
 Retail business: enlarged the customer base by approximately 130,000 delivery points in the
nine months of 2019 due to growth in the power business and outside Italy; expected
additional growth by the end of the year.
 Adjusted operating profit G&P: €93 million in the third quarter of 2019, up by 31% compared
to the third quarter of 2018; €511 million in the nine months (up by 2%). The performance
was mainly driven by optimizations of the gas assets portfolio in Europe which captured the
high market volatility and by growth in the result of the retail business.
Refining & Marketing and Chemicals
 Closed the acquisition of 20% stake in ADNOC Refining in Abu Dhabi, for a consideration of
$3.24 billion, including the 20% of a Trading Joint Venture for oil products marketing to set-
up. The transaction is part of Eni’s strategy targeting geographical diversification of the
portfolio in order to balance it along Eni’s value chain, with a 35% increase in its refining
capacity.
 In August 2019, the Gela Green Refinery started-up which is ramping up toward the target
processing capacity of 750,000 tonnes per year.
 Strong recovery in the R&M business results: adjusted operating profit of €0.22 billion in the
third quarter of 2019, representing a three-fold increase compared to a year-ago (up by 54%
from the third quarter of 2018) due to a robust marketing performance in the peak demand
period and a recovery in refining margins at simple throughputs as pointed out by trends in
the Company’s SERM2, offset by a continued deterioration in price differentials between
heavy crudes vs. the Brent crude. In the nine months, operating profit at €0.28 billion was up
by 29% due to a better performance of marketing activity, while the refining business was
affected by a weaker refining scenario for complex throughputs and unplanned refinery
downtime.
 Adjusted result of the Chemical business: operating loss of €70 million in the third quarter in
a persistent difficult environment. In the nine months the operating loss was €144 million,
negatively affected by the scenario, the incident at the Priolo steam-cracker, and by
unplanned shutdowns.
Decarbonization and circular economy
 Energy Solutions, power generation from renewables: 42 MW of installed capacity as of
September 30, 2019. The main initiatives of the quarter are specified below:
o the acquisition of two construction-ready solar photovoltaic projects in the Northern
Territory of Australia, 12.5 MW each at Batchelor and Manton sites, scheduled for
completion by the third quarter of 2020;
o a co-operation agreement with Mainstream Renewable Power, the wind and solar
development company, to develop projects in high-growth markets;

o an allotment to ArmWind LLP, joint venture between Eni and General Electric, of a
project for a 48 MW wind farm in the Northern Kazakhstan following a reverse auction.
Began construction of the following plants:
 Badamsha, in Kazakhstan, a 50 MW wind farm;
 Porto Torres (Sassari), a 31 MW photovoltaic plant and a 18 MW plant at Volpiano (Turin),
in Italy;
 Katherine, in Northern Australia, a 33.7 MW photovoltaic plant, equipped with a storage
system;
 Tataouine, in Southern Tunisia, a 10 MW (Eni 50% interest) photovoltaic plant, and Adam,
located near the homonymous oil concession, a 5 MW (Eni 50% interest) photovoltaic plant;
 Bhit in Pakistan, a 10 MW photovoltaic plant.
 Installed generation capacity expected at 190 MW by year-end.
 Eni has been confirmed as a Global Compact LEAD participant, as a result of its ongoing
commitment to the United Nations’ Sustainable Development Goals (SDGs).
 Signed a number of MOUs to develop circular economy projects, targeting mainly the recycling of
solid urban waste to convert it in bio-feedstock.
 Signed a joint declaration with the United Nations Industrial Development Organization, setting up an
innovative public-private cooperation model aimed at enhancing the UN’s SDGs.
Group results
 Adjusted operating profit: €2.16 billion in the third quarter, down by 35% q-o-q (€6.79 billion
in the nine months, down by 18%). Excluding the impact of the loss of control over Eni Norge
on the 2018 results to allow a-like-for-like comparison, and net of scenario effects and IFRS
16 accounting, the Group adjusted operating profit decreased by 1% in the quarter (a 4%
increase in the nine months).
 Adjusted net profit: €0.78 billion for the quarter, down by 44% q-o-q (down by 42% excluding
IFRS 16 accounting effects); €2.33 billion in the nine months, down by 26% (down by 23%
excluding IFRS 16 accounting effects).
 Net profit: €0.52 billion and €2.04 billion in the quarter and the nine months, respectively.
 Cash flow before working capital at replacement cost3: €2.6 billion (down by 23%) and €9.4
billion (up by 5%) in the third quarter and in the nine months of 2019, respectively (€2.4 billion
in the quarter; €8.9 billion in the nine months of 2019 when excluding IFRS 16 accounting
effects). Cash generation was negatively affected by lower gas prices, mainly in Europe, with
an impact of €340 million in the quarter and €520 million in the nine months.
 Cash flow provided by operating activities: €2.06 billion in the third quarter (down by 50%);
€8.67 billion in the nine months (down by 7%), which was negatively affected by an
extraordinary payment to settle an arbitration outcome (€330 million).
 Capital expenditure and investment, net: €5.6 billion in the nine months, net of the acquisition
of ADNOC Refining and hydrocarbons reserves (IFRS 16 effects were immaterial).

 Net borrowings: €12.7 billion before the effect of IFRS 16, up by 53% from 2018 year-end
mainly due to the acquisition of a 20% interest in ADNOC Refining (€2.9 billion), net capex
of €5.6 billion and cash returns to shareholders for €3.24 billion. Including IFRS 16, net
borrowings was €18.5 billion, of which around €2 billion pertains to the share of lease
liabilities attributable to joint operators in Eni-led upstream project.
 Leverage: 0.25 before the effect of IFRS 16, higher than the values at December 31, 2018
(0.16) and June 30, 2019 (0.15) having accounted for the acquisition of a 20% interest in
ADNOC Refining, net capex and cash returns to shareholders. Including IFRS 16, leverage
was 0.36, or 0.32 excluding the share of lease liabilities attributable to E&P joint operators.
 Buy-back: the buy-back program of Eni’s shares started at June 5, 2019; as of September
30, 2019 16.2 million of shares have been repurchased for a total consideration of €229
million.
Outlook 2019
Exploration & Production
Hydrocarbon production: reaffirmed the target of a production plateau in the range of 1.87 -1.88
mmboe/d, assuming a Brent price forecast of 62 $/bbl. The projected range assumes a degree of
volatility in the Asian demand for LNG and in Venezuelan production. As previously anticipated,
production growth has been faster in the third quarter which was nonetheless affected by residual
maintenance activity. Production is expected to ramp-up further in the fourth quarter.
New field start-ups and ramp-ups are projected to add approximately 250 kboe/d of new production
in the year, mainly relating the Zohr field, the achievement of full production at fields started in 2018,
particularly in Libya, Ghana and Angola, as well as the fields started in 2019, mainly the Area 1 oil
project offshore Mexico, Baltim SW in Egypt, North Berkine in Algeria and the Trestakk project in
Norway and other additions. Those increases are expected to more than offset mature field declines.
Exploration resources: equity additions for the year expected at 700 million boe.
Gas & Power
Operating profit: expected at approximately €600 million.
Portfolio of retail customers projected to increase due to the development of the power business
and activities outside Italy.
Refining & Marketing and Chemicals
Refinery breakeven margin expected at approximately 5.2 $/bbl in 2019 reflecting an
unfavourable trading environment due to narrowing differentials between heavy/sour crudes and
the light Brent crude and with the industrial system running below full operations. At the budget
scenario and at full capacity, the breakeven margin would be 3.5 $/bbl at the end of 2019.
R&M pro-forma operating profit (including the contribution of ADNOC Refining): revised down
to €400 million, due to a further deterioration in the scenario for complex refineries in the third
quarter, which has been stabilizing lately.
Refinery throughputs on own account: substantially unchanged.
Green throughputs: an increase expected due to the start-up of the Gela plant.

Retail sales of refined products seen as stable, in line with the market share in Italy.
Petrochemical production volumes and sales: expected to decline y-o-y due to the shutdown of
the Priolo steam-cracker in the first quarter and fully in operation by the end of July, as well as other
unplanned standstills. Sale volumes are expected to be significantly affected by a slowdown in
demand from the automotive sector and by weaker demand of “single-use plastics”.
Group
Capex: revised a slight decrease in the previous guidance of €8 billion for FY 2019 at the budget
exchange rate of 1€=1.15 USD.
Cash flow from operations before working capital at replacement cost: confirmed guidance of
approximately €12.8 billion at the budget scenario assumptions, before IFRS 16 effects.
Cash neutrality: organic capex and the dividend are expected to be fully funded by operating cash
flows at the Brent scenario of 55 $/bbl before IFRS 16 effects, or 52 $/bbl including IFRS 16 effects.

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 2019 K. Al Awadi

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