New base energy news 16 november issue 1295 by khaled al awadi

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NewBase Energy News 16 November 2019 - Issue No. 1295 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:Eni to begin Oman offshore Block 52 drilling in February
Oman Observer + NewBase
Italian energy giant ENI is set to make its offshore debut in the Arabian Gulf region with the drilling
of a maiden well next February in Block 52, a sprawling deepwater concession that extends off
Oman’s southern and south-eastern seaboard.
ENI Chief Executive Officer Claudio Descalzi made the announcement in an interview to
Bloomberg TV on the sidelines of the opening of ADIPEC 2019 in Abu Dhabi earlier this week.
ENI’s local subsidiary ENI Oman BV is the operator of Block 52 — a massive 90,790 square
kilometre concession — with a 55 per cent stake. Qatar Petroleum holds a 30 per cent interest,
while Oman Oil Company Exploration & Production (OOCEP) — the upstream investment arm of
Oman Oil & Orpic Group — owns the balance 15 per cent.

“The first drilling that we are doing in the region will be in Oman in February — it will be the first
(deepwater) offshore drilling in Block 52 in Oman; so it’s quite important,” said Descalzi.
The exploration well is planned barely seven months after the completion of the acquisition of
seismic, said the official, describing the pace as an “achievement”. As for the nature of the
hydrocarbons expected to be unlocked by the drilling programme, he said “it’s likely to be gas-
condensate”.
The Block 52 drilling will be followed by drilling activity in Bahrain and then Abu Dhabi, where ENI
has upstream assets. “We have a programme (to drill) about 10 wells in the next couple of years,
so it’s going to be very intense exploration activities,” said the CEO.
Although largely unexplored, Block 52 is believed to be prospective for hydrocarbon resources
based on evidence of the presence of petroleum systems in the block.
Water depths range from 10 metres near the coast to 3,000 metres at the deep end, underscoring
the challenges for Eni in the exploration and production, if any, of subsea resources.

Iraq: DNO testing Baeshiqa-2 exploration well in Kurdistan
Source: DNO
DNO, the Norwegian oil and gas operator, has announced issuance of a notice of discovery to the
Kurdistan Regional Government of Iraq on the Baeshiqa-2 exploration well, in accordance with the
requirements of the Production Sharing
Contract, after flowing hydrocarbons to
surface from the upper part of the
Triassic Kurra Chine B reservoir.
Following acid stimulation, the zone
flowed variable rates of light oil and
sour gas. Further testing of this and
other Jurassic and Triassic zones is
ongoing and will determine the next
steps towards appraisal and
assessment of commerciality.
The Baeshiqa-2 well was spud in
February 2019 and drilled to a total
depth of 3,204 meters (2,549 meters
TVDSS).
DNO acquired a 32 percent interest
and operatorship of the Baeshiqa
license in 2017. Partners
include ExxonMobil with 32
percent, Turkish Energy Company with
16 percent and the Kurdistan Regional
Government with 20 percent.

U.S: EPA small refinery exemptions in the Renewable Fuel
Standard explained… Source: U.S. EIA based on EPA Moderated Transaction System
The Renewable Fuel Standard (RFS) mandates the amount of renewable fuels refineres must
blend into the U.S. transportation fuel supply. As part of the RFS program, the U.S. Environmental
Protection Agency (EPA) can grant annual waivers to some petroleum refineries, called small
refinery exemptions (SREs), which are provided under conditions of economic hardship.
Although these SREs lessen the number of tradable compliance credits that refineries can use to
comply with the RFS program, actual biofuel consumption is influenced by additional market
factors.
Note: RFS is the Renewable Fuel Standard program.
The Clean Air Act, as amended by the Energy Policy Act of 2005, exempted small refineries from
participating in the RFS program through the 2010 compliance year. The EPA later extended
these exemptions for 2011 and 2012.
Starting in the 2013 compliance year, small refineries—those rated at less than 75,000 barrels per
day (b/d) of crude oil throughput—could petition EPA for an exemption if RFS compliance would
cause disproportionate economic hardship for the refinery. SRE waivers exempt petroleum
refineries from their renewable volume obligation (RVO), typically for the previous compliance
year.
The EPA sets targets for the amount of renewable fuel to be blended into petroleum-based
gasoline and diesel annually. On November 30, 2017, EPA issued an overall RFS target of 19.29
billion gallons of renewable fuel for the 2018 compliance year.
Renewable identification numbers, or RINs, are the compliance credits used in the RFS program.
RINs are generated when renewable fuels are produced domestically or imported. To meet their
obligations, refineries may blend renewable fuel or purchase RINs from other parties that have not
used (or retired) RINs for compliance, or obtain an SRE from the EPA. SREs are typically
approved retroactively after the previous compliance year has ended. On August 9, 2019, EPA

approved 31 SREs, which was equivalent to 1.43 billion RINs, or about 7.4% of the 19.29 billion
gallon target of renewable fuel for the 2018 compliance year.
Because SRE waiver approval is uncertain and retroactively applied, small refineries may
consider other factors when making decisions on blending renewable fuels. Key market factors
include the cost of blending renewable fuels relative to the cost of motor gasoline and diesel. In
the United States, most motor gasoline contains 10% fuel ethanol, or E10, which is the most cost-
effective method to boost the fuel’s octane content to meet fuel specifications.
Although SRE waivers effectively exempt some of the renewable fuel mandate for a compliance
year, the actual amount of available renewable fuel not blended into the U.S. transportation fuel
pool as a result of SREs can be difficult to estimate. EPA does not disclose which refineries
received exemptions, and the U.S. Energy Information Administration’s (EIA) published refinery
data is aggregated at the regional level.
The estimated volume of exempt RINs in a compliance year is based on the number and capacity
of refineries receiving exemptions. More waivers do not necessarily mean more exempt volumes:
for example, the number of exempt refineries decreased from 2013 to 2015, but the number of
estimated exempt RINs increased. As of November 2019, EPA approved 31 SREs for the 2018
compliance year and 2 SRE applications are still pending.
RINs created by biofuel producers and importers are not necessarily paired immediately with an
unblended gallon of fuel. Each RIN is valid for more than one compliance year and expires after
two years, meaning some RINs can be banked for future compliance or trade. RFS rules allow the
use of RINs generated in the previous year (banked RINs) to satisfy up to 20% of the current
year’s RVO targets.
Banked RINs provide a buffer between the physical blending of renewable fuels and any shortfalls
in annual RVO targets. Currently, the transparency on the amount or details regarding these RINs
is limited. In particular, the extent that refineries use banked RINs to meet compliance obligations
in each year is unclear.
Although the number of RINs refineries use to comply with the RFS program has generally
increased since the 2014 compliance year, EIA expects U.S. biofuels consumption to remain
mostly stable in 2019 and 2020, based on its most recent Short-Term Energy Outlook.

U.S. natural gas production, consumption, and exports
set new records in 2018
Source: U.S. Energy Information Administration, Natural Gas Annual 2018
The U.S. Energy Information Administration’s (EIA) Natural Gas Annual 2018 shows that the
United States set new records in natural gas production, consumption, and exports in 2018.
In 2018, dry natural gas production increased by 12%, reaching a record-high average of 83.8
billion cubic feet per day (Bcf/d). This increase was the largest percentage increase since 1951
and the largest volumetric increase in the history of the series, which dates back to 1930. U.S.
natural gas consumption increased by 11% in 2018, driven by increased natural gas consumption
in the electric power sector.
Natural gas gross exports totaled 10.0 Bcf/d in 2018, 14% more than the 2017 total of 8.6 Bcf/d.
Several new liquefied natural gas (LNG) export facilities came online in 2018, allowing for more
exports.

U.S. natural gas consumption grew in each end-use sector. Demand for natural gas as a home
heating fuel was greater in 2018 than in 2017 because of slightly colder weather during most of
the winter.
Similarly, the summer of 2018 saw record-high temperatures that increased demand for air
conditioning and, therefore, electricity—much of which was fueled by natural gas. U.S. electric
power sector consumption of natural gas grew by 14% in 2017, more than in any other end-use
sector.
The electric power sector has been shifting toward natural gas in the past decade because
of favorable prices and efficiency gains.
U.S. natural gas production growth was concentrated in the Appalachian, Permian,
and Haynesville regions.
Pennsylvania and Ohio, states that overlay the Appalachian Basin, had the first- and third-largest
year-over-year increases for 2018, increasing by 2.0 Bcf/d and 1.7 Bcf/d, respectively.
Louisiana had the second-largest volumetric increase in dry production, increasing by 1.8 Bcf/d as
a result of increased production from the Haynesville shale formation. Texas remained the top
natural gas-producing state, with a production level of 18.7 Bcf/d, as a result of continued drilling
activity in the Permian Basin in western Texas and eastern New Mexico.

Venezuela Is Secretly Exporting Millions of Barrels of Oil
Bloomberg + NewBase
The Dragon, a massive oil tanker flying the Liberian flag, is supposed to be floating somewhere off
the coast of France, according to its last GPS signal.
Instead, it’s currently thousands of miles away in Venezuela where, under contract for the Russian
state-oil giant Rosneft Oil Co PJSC, it loaded 2 million barrels of oil, according to data compiled by
Bloomberg and shipping reports.
How’s that possible? Because the ship’s transponders were turned off before it slipped into
Venezuelan waters, the data shows.
The practice of oil tankers turning off their location signals has increased in the past month,
according to shipping data, after the U.S. went after a Chinese-owned shipping company it said
was moving crude for sanctioned Iran.
The U.S. is seeking to squeeze the Nicolas Maduro government in Venezuela by starving it of oil
revenue. But more and more tankers appear to be using the technique to avoid penalties, helping
give a boost to Venezuelan crude output that has plummeted since the U.S. imposed sanctions.

Venezuela loaded 10.86 million barrels of crude oil in the first 11 days of November, more than
double the volume in the same period last month. About half of those barrels were loaded onto
ships that had turned off their transponders, which later delivered cargoes to China and India, data
compiled by Bloomberg show.
Dynacom Tankers Management Ltd., the manager for the Dragon, said in an emailed statement
that “since January 2019 none of the vessels under our management ever entered into any
contract with any U.S. sanctioned entity, nor have they ever violated any U.S sanction either
related to Venezuela or otherwise.” The company didn’t comment on why the signal for the
Dragon has been off for the past three weeks or confirm if the vessel was docked in the South
American country.
Rosneft, meanwhile, said in an emailed statement that its operations involving Venezuela “fully
comply with all the rules of international law.” The statement didn’t specifically address the use of
transponders.
While it’s possible that
transponders, known as
Automatic Identification
Systems, can go offline,
they are typically not out for
long. The practice of hiding
ships carrying oil isn’t new,
and can be done for
competitive purposes or for
other reasons. Iran, another
OPEC member sanctioned
by the U.S. government,
also uses dark ships to
export its oil.
The U.S. recently targeted Chinese oil-importers and shippers such as Zhuhai Zhenrong Co. and
a unit of COSCO Shipping Corp. for allegedly handling Iranian crude. Zhuhai and COSCO
routinely operate their vessels with the signal turned on, ship-tracking data shows.
Venezuelan oil production -- crippled by U.S. sanctions that have limited its buyers and curtailed
access to oil tankers -- slumped to a fresh 16-year low of 644,000 barrels daily in September,
cutting off funds badly needed by the Maduro regime. Unsold oil filled storage tanks and vessels,
forcing operators to shut-in production at Venezuela’s oil-producing frontier known as Faja.
Earlier this year Venezuela masked deliveries to Cuba by renaming sanctioned vessels and
turning off the satellite tracking system, according to shipping data. The Trump administration
wants to cut off the supply of oil to the Caribbean country because it helps to pay for intelligence,
defense and security assistance to Maduro, the U.S. Treasury Department said.
Going dark became more common after companies including Unipec, the trading arm of China’s
state-owned oil giant Sinopec, banned the use of oil tankers that have operated in Venezuelan
ports over the previous 12 months.
While Unipec made an official addendum to its charter contracts, others informally avoid ships that
have Venezuela as the last port of call, according to people with knowledge of situation. Demand
for Venezuelan oil ticked up this month as state oil company Petroleos de Venezuela SA won
back customers, including the Indian refiner Reliance Industries Ltd. Tipco Asphalt Public Co. Ltd.,
a refiner from Thailand, is also lifting Venezuelan oil in November after a two-month absence.

NewBase 16 November 2019 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices gain 2% despite concerns about rising supplies
Reuters + NewBase
Oil futures gained nearly 2% on Friday as comments from a top U.S. official raised optimism for a
U.S.-China trade deal, but worries about increasing crude supplies capped prices.
Brent crude gained $1.02, or 1.6%, to settle at $63.30 a barrel, while West Texas Intermediate
crude rose 95 cents, or 1.7%, to settle at $57.72 a barrel. Both benchmarks posted their second
straight weekly gain. Brent rose 1.3%, and WTI gained 0.8%.
U.S. Commerce Secretary Wilbur Ross said in an interview on Fox Business Network that there
was a very high probability the United States would reach a final agreement on a phase one trade
deal with China.
“We’re down to the last details now,” Ross said. U.S.-China trade talks were set to continue with
a telephone call on Friday. A monthly report from the International Energy Agency weighed on
prices, after it estimated that non-OPEC supply growth would surge to 2.3 million barrels per day
Oil price special
coverage

(bpd) next year compared with 1.8 million bpd in 2019, citing production from the United States,
Brazil, Norway and Guyana.
“Today’s monthly IEA release offered some bearish aspects in the form of an unexpected upward
adjustment in non-OPEC oil supply growth for next year that briefly forced WTI values to below
yesterday’s lows,” said Jim Ritterbusch, president of Ritterbusch and Associates.
OPEC Secretary General Mohammad Barkindo had painted a more upbeat picture earlier this
week, saying growth in rival U.S. production would slow in 2020, although a report by the group
had also said demand for OPEC oil was expected to dip.
The Organization of the Petroleum Exporting Countries said demand for its crude would average
29.58 million bpd next year, 1.12 million bpd less than in 2019, pointing to a 2020 surplus of about
70,000 bpd.
OPEC and its allies, known as OPEC+ which have cut supply this year to prop up prices, are
expected to discuss output policy at a meeting on Dec. 5-6 in Vienna. Their existing production
deal runs until March.
U.S. production has continued climbing. The country’s crude oil output hit a record 13 million bpd
this month and will grow more than expected in 2019 and 2020, the U.S. Energy Information
Administration said in a forecast issued on Wednesday.

However, rising U.S. output and competition from production in Brazil, Norway and Guyana next
year has been squeezing profits for U.S. shale producers, which plan another spending freeze in
2020 and a slowdown in production growth.
U.S. energy firms this week reduced the number of oil rigs operating for a fourth week in a row,
cutting 10 oil rigs in the week to Nov. 15, energy services firm Baker Hughes Co said on Friday.
The total count is now 674, the lowest since April 2017.
Money managers raised their net long U.S. crude futures and options positions by 39,995
contracts to 169,386 in the week to Nov. 12, the U.S. Commodity Futures Trading Commission
(CFTC) said on Friday.
U.S. oil drillers cut rigs for fourth week in a row: Baker Hughes
U.S. energy firms this week reduced the number of oil rigs operating for a fourth week in a row as
producers plan to slash spending for a second consecutive year in 2020 while they struggle to
extract profits from the shale boom.
Drillers cut 10 oil rigs in the week to Nov. 15, bringing the total count down to 674, the lowest
since April 2017, energy services firm Baker Hughes Co said in its closely followed report on
Friday. In the same week a year ago, there were 888 active rigs.
Producers expect to spend about $4 billion less in 2019 than in 2018, according to U.S. financial
services firm Cowen & Co, as independent exploration and production companies cut spending on
new drilling as shareholders seek better returns in a low energy price environment.

So far, 21 exploration and production companies tracked by Cowen have released 2020 capex
guidance with 15 projecting declines, five with increases and one unchanged, for a 13% year-
over-year spending decline.
The oil rig count, an early indicator of future output, has already declined for a record 11 months in
a row, but output has continued to increase in part because productivity of those remaining rigs -
the amount of oil new wells produce per rig - has increased to record levels in most shale basins.
The U.S. Energy Information Administration projected U.S. crude output will rise to 12.3 million
barrels per day (bpd) in 2019 from a record 11.0 million bpd in 2018.
U.S. crude futures traded below $58 per barrel on Friday, putting the contract on track to rise for a
second week as the U.S. and China make progress on trade talks that could boost global
economic growth and oil demand.
Looking ahead, U.S. crude futures were trading around $56 a barrel in calendar 2020 and $53 in
calendar 2021. Year-to-date, the total number of oil and gas rigs active in the United States has
averaged 961. Most rigs produce both oil and gas.
Analysts at Simmons & Co, energy specialists at U.S. investment bank Piper Jaffray, forecast the
annual average combined oil and gas rig count will slide from a four-year high of 1,032 in 2018 to
951 in 2019 and 906 in 2020 before rising to 957 in 2021.

NewBase Special Coverage
News Agencies News Release 16 August 2019
Oil & gas to meet global energy demand in 2040: Opec
Trade Arabia + Newbase
There will be a 25 per cent increase in total primary energy demand worldwide between 2018 and
2040, with oil and gas expected to meet most of this demand, Opec secretary general
Mohammad Sanusi Barkindo told industry leaders at the Abu Dhabi International Petroleum
Exhibition and Conference (Adipec).
Oil and gas will continue to play a central role in
achieving sustainable economic development and
reducing ‘energy poverty’, he added, presenting data
from the 2019 Opec World Oil Outlook.
He said growth would be driven by rising demand in
developing countries, where almost one billion people
still lacked access to electricity and three billion had no
access to clean fuels for cooking. “All forms of energy
will be required to meet this expanded demand in a sustainable way,” Barkindo said during his
presentation.
“Renewables are contributing the largest growth in percentage terms, including significant
expansion in investment in Opec member countries, particularly here in the UAE. Natural gas has
the largest growth in terms of replacing coal (for electricity generation), and oil retains its role with
the largest share in the energy mix.

“In fact, oil and gas combined are still expected to make up more than 50 per cent of the energy
mix at 2040.”
He said the proportion of demand coming from China, India and other emerging markets would
continue to grow, particularly from Asia-Pacific markets. Non-OECD demand would increase by
21.4 mb/d (million barrels per day) by 2040, compared with 2018 figures, while the OECD was
expected to reduce by 9.6 mb/d. Total oil demand was expected to reach 110.6 million barrels,
with an estimated $10.6 trillion of investment needed across the upstream, midstream and
downstream sectors.
However, he noted that it was important that growth be achieved within the context of reducing
carbon emissions and – and that new technologies must be developed to ensure the industry
could contribute to economic growth, while also helping limit climate change.

“The oil industry must be part of the solution to the climate change challenge,” Barkindo said. “The
science tells us that we need to reduce emissions, it does not tell us that we need to choose one
energy over another. Thus, we need to continually evolve and adopt cleaner energy technologies
across the board, ones that enable us to meet expected future energy demand, in a sustainable
and ever more efficient manner, and where no-one is left behind.”
Barkindo led Opec experts in providing an overview of the 2019 edition during Oil and Gas 4.0,
Adipec’s landmark strategic conference. Since its inauguration in 1984, Adipec has continued to
grow, gaining worldwide recognition as the premier oil and gas industry exhibition and conference.
The exhibition brings together over 2,200 international exhibiting companies across 160,000 gross
square metres, with 23 country pavilions, attracting over 150,000 global attendees and 51 national
and international oil companies. The conference hosts over 980 strategic and technical speakers
across more than 160 sessions, covering the full energy value chain and attracting over 10,400
delegates.

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
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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
Mobile: +97150-4822502
khdmohd@hawkenergy.net
khdmohd@hotmail.com
Khaled Al Awadi is a UAE National with a total of 25 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

New base energy news 16 november issue 1295 by khaled al awadi

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New base energy news 16 november issue 1295 by khaled al awadi