Microsoft word new base 995 special 05 february 2017 energy news

Copyright © 2015 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,
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NewBase 05 February 2017 - Issue No. 996 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: Abu Dhabi Said to Improve Oil-Investor Returns
With New Terms
Bloomberg - Anthony Dipaola
Abu Dhabi’s state energy producer, which is seeking more partners to develop its fields, improved
some terms in an oil-production partnership to offer greater returns to international companies
such as BP Plc and Total SA, according to people with knowledge of the matter.
Abu Dhabi National Oil Co. improved terms related to taxation and depreciation for companies in
the venture, known as Abu Dhabi Co. for Onshore Petroleum Operations, or ADCO, said the
people, who asked not to be identified because the negotiations were private. The provisions were
changed when BP joined in December, they said.
The United Arab Emirates, of which Abu Dhabi is the capital, is boosting its production capacity
even as it diversifies away from oil to build new industries and create jobs. Adnoc is partnering
with European and American companies that have pumped oil in the Middle East for more than a

century as well as with comparative newcomers to the region from Asia to contribute technology
needed to extend the life of its oil and natural gas reserves.
Total and BP each hold 10 percent stakes in ADCO, while Japan’s Inpex Corp. owns 5 percent
and GS Energy of South Korea 3 percent. Adnoc, which aims to retain 60 percent of the venture,
is seeking partners for the remaining 12 percent of ADCO.
The ADCO concession terms, which remain fundamentally unchanged, apply to all existing and
future partners, an Adnoc media official said, asking not to be identified by name, in line with
company policy.
Boosting Capacity
ADCO pumps about half of Abu Dhabi’s roughly 3 million barrels of daily crude output. The
emirate, with about 6 percent of global oil reserves, is seeking to boost its production capacity to
3.5 million barrels a day by 2018.
BP has worked in Abu Dhabi since 1939 and was a partner in the emirate’s previous onshore oil
concession, which expired in 2014 after 75 years. Total was the first company to sign a new
contract to continue developing the fields; the Paris-based company agreed in January 2015 to
pay a $2.2 billion signing bonus to Adnoc.
BP sought a stake in the renewed concession before plunging crude prices and damages related
to the Deepwater Horizon oil spill in the Gulf of Mexico forced the company to break off talks.
“It just took us a while to work through the point where we could make this great investment with
Abu Dhabi,” BP Chief Executive Officer Bob Dudley said in December. “The key element there is
we’ve used BP shares,” he said. The company issued about $2.2 billion in stock and transferred it
to Abu Dhabi for its stake in the ADCO venture.
Gulf crude producers have pressed on with major investment projects, even amid the slump in
prices, to maintain their share of global markets and head off supply shortages in coming years.
U.A.E. Energy Minister Suhail Al-Mazrouei has warned that reduced spending on new projects
over the last three years could lead to a supply shortfall.
BP, Total and Inpex are also partners with Adnoc in an offshore production venture, which expires
next year. 2

Saudi Arabia creates unit to focus on renewable energy
The National LeAnne Graves
Saudi Arabia’s energy ministry has created a new division to drive the kingdom’s renewable
energy plan, which will begin reviewing interested companies for projects this month.
The Renewable Energy Project Develop Office (Repdo), falling under the energy ministry, will be
led by a committee that includes the major energy players in the country from Saudi Aramco,
Saudi Electricity Company, Electricity and Cogeneration Regulatory Authority and King Abdullah
City for Atomic and Renewable Energy.
"This dedicated team will assume overall responsibility for the execution and delivery of the
programme, starting with the launch of the request for qualifications process on February 20," said
Khalid Al Falih, Saudi Arabia’s energy minister.
The first movement for the National Renewable Energy Program (NREP) will start accepting
applications later this month from companies looking to participate in developing 700 megawatts
of solar and wind projects. The next milestone will be the request for proposals issued in mid-April
and the first projects will be awarded in September.
The NREP is the official plan for the 9.5 gigawatts of renewable energy deployment that the
government announced for Vision 2030, with the interim target of 3.45GW of renewable energy
power capacity by 2020 under the National Transformation Programme.
The first phase will see projects developed in the northwest of the country – 300MW of solar in
Sakaka at the An Nafud desert while Midyan will have 400MW of wind. Midyan is also the site of
Saudi Aramco’s Midyan gas plant which will produce 570MW of power once complete, including
50MW of solar from a nearby plant.

Japan’s Sumitomo Mitsui Banking Corporation will be the financial adviser throughout the tender
process with London-based DLA Piper as legal adviser. Fichtner Group of Germany will be the
technical adviser, the same role it plays for Abu Dhabi’s Sweihan solar project.

Iraq’s South Oil Exports Said to Fall From Record on OPEC Cuts
by Khalid Al Ansary
Iraq’s southern crude oil exports dropped in January from a record high a month before as the
country implements output cuts agreed by OPEC and other major producers to curb the global
glut.
The nation’s exports decreased 187,000 barrels a day to 3.323 million barrels a day in January
from the previous month, according to a person familiar with the matter, who didn’t want to be
identified because the data isn’t public. The Oil Ministry’s spokesman couldn’t immediately be
reached on Friday, which is a weekly holiday in Iraq.
Shipments in January from the South Oil Co. were 3.278 million barrels a day and exports from
the North Oil Co. 45,000 barrels a day, the person said. Iraq’s exports from the south had risen to
a record average of 3.51 million barrels a day in December, Oil Minister Jabbar Al-Luaibi said on
Jan. 9.
OPEC and 11 other major-producing countries including Russia agreed late last year to cut a
combined 1.8 million barrels a day of output for six month starting from January, with Iraq’s share
set at 210,000 barrels. Some analysts expressed doubts that Iraq would deliver its share of the
cuts, potentially undermining the drive to rebalance the market and drain inventories bloated by
two years of unfettered production that helped to crash prices.
During the months of negotiation that led to November’s OPEC agreement, Iraq had insisted
repeatedly that it should be exempted from cuts as it battles the Islamic State insurgency and
rehabilitates its oil industry after years of war and sanctions. The country also disputed the data to
be used in any discussions, insisting that numbers compiled by OPEC underestimated Iraqi
production by about 5 percent. Iraq ultimately relented, agreeing to reduce its output.
Iraq was close to implementing its share of the agreed production cuts and would be in full
compliance by the end of the month, Al-Luaibi said Jan. 23. The Middle Eastern producer had
already reduced output by 180,000 barrels a day and would cut another 30,000 soon, the minister
said in a Bloomberg television interview.

Libya: OMV restarts production in Libya and expands operations
Source: OMV
• OMV’s production in Libya is expected to reach 10,000 bbl/d on average in 2017
• OMV increased its stake in four Exploration and Production Sharing Agreements in the
Sirte Basin and strengthened the partnership with the National Oil Corporation (NOC)
Given the improvement in the political and security situation in Libya, OMV successfully started up
production in both the Sirte and Sharara oil fields. The Sharara fields are located in the Murzuq
basin. In Q4/2016 OMV’s production from Libya amounted to approx. 3,000 bbl/d.
OMV also increased its stake in four Exploration and Production Sharing Agreements (EPSAs) in
the Sirte Basin. OMV acquired 75% of the Second Party Share and now holds 100% of the
Second Party shareholding in Blocks C103, NC29/74, C102 and Nafoora Augila. The state-owned
Libyan national oil corporation NOC holds the First Party Share and will remain the majority
shareholder with a working interest of 88 to 90%.
OMV’s Libyan production is expected to reach 10,000 bbl/d on average in 2017. Subject to
ongoing improvements in the security situation, the above transaction will provide OMV with an
opportunity to increase its production in Libya to a maximum of 50,000 bbl/d.
'OMV has been a trustful partner to NOC throughout challenging times and remains fully
committed to invest in Libya in the future', said Rainer Seele, CEO and Chairman of the OMV
Executive Board after meeting with NOC Chairman Mustafa Sanalla in Tripoli.

Tunisia: Serinus Energy resumes production at the Chouech Es Saida
Source: Serinus Energy
Serinus Energy has resumed production at the Chouech Es Saida field in Tunisia. The field was
initially shut-in on January 10, 2017, in anticipation of a three-day strike with production stoppage,
as voted for by the Company's employees at the Winstar Chouech Es Saida facilities, which
began at midnight January 11, 2017.
The labour action
continued with a sit-in that
persisted after the
communicated work action,
with the Company being
unable to bring production
back on line for safety and
security reasons.
For the past two years, the
Company has been
engaged in ongoing
dialogue with the Tunisia
General Trade Union
('UGTT') regarding the
need for the Company to
reduce operating costs at
Chouech Es Saida due to
the economic situation in
the sector.
Through ongoing dialogue
between the Company and UGTT during this work action, the Company has agreed to resume
production at Chouech Es Saida as an act of good faith in exchange for the ending of the sit-in
and the agreement of UGTT to cooperate in the ongoing economic redundancy process.
The ending of the sit-in on January 29, 2017, has removed the safety and security concerns the
Company had in continuing operations of the Chouech Es Saida field and the cooperation of
UGTT in the economic redundancy program provides the Company with sufficient encouragement
to re-start production as a gesture of goodwill.
The staff reductions of the economic redundancy program are necessary for the Company to
further reduce operating costs and to remain a viable Tunisian employer and producer of
hydrocarbons.
The Company has procured a replacement electrical submersible pump for the CS-3 well and
anticipates that this pump will be delivered to the Company by mid-February 2017. With the
delivery of the pump, the Company will begin a workover program on the CS-3 well and install the
new pump in the well. It is estimated that the CS-3 well will back on production by early April,
2017.
Serinus Energy is an international oil and gas exploration and production company dual listed on Warsaw Stock Exchange and
Toronto Stock Exchange.
Our portfolio comprises 6 operated licenses in 2 countries and it covers the full-cycle of upstream value chain - from high impact exploration
potential through appraisal and development to the constantly increasing production. Due to its experienced management team with proven fast-
track development skills and an intensive exploration and development program, Serinus Energy is uniquely positioned to deliver strong, long-term
growth to its shareholders.

GCC 'needs $137bn' in power projects in the next 5 years
By Sarah Townsend
The GCC power sector requires $137 billion of investment over the next five years to cope with
rising demand, a new report claims.
Capacity in the region needs to expand at an average annual pace of 8 percent between 2016
and 2020. This will require an estimated $85 billion for the addition of 69 gigawatt (GW) of
generating capacity and a further $52 billion for transmission and distribution, the report by
construction research firm Ventures Onsite states.
The report forecasts a 14 percent year-on-year increase in GCC power construction contractor
awards in 2017. The total value of contracts awarded is set to increase from $22.381 billion in
2016 to $25.523 billion in 2017, the report says.
Saudi Arabia is expected to register the highest contractor awards in 2017, at around $12.34
billion, an increase of over 50 percent from its 2016 figure. The report predicts the value of power
construction contract awards will also significantly increase in Bahrain, Kuwait and Oman.
GCC countries are set to invest a total of $252 billion over the next five years in projects for setting
up new power production plants, distribution systems and supply grids, Ventures Onsite notes.

Many are implementing reforms to the structure of the electricity market – for example, increasing
water, electricity and fuel prices to ease the burden on state budgets. This is all part of a broader
programme to liberalise domestic energy prices over the medium term, the report adds.
There has also been a growing interest in
‘smart’ power grids that more efficiently
produce and distribute power according to
immediate demand, thereby reducing stress on
grids, cutting emissions and defer investments
for upgrades.
Holley Chant, executive director of corporate
sustainability at energy consultancy KEO
International, said: “The elephant in the room
for energy efficiency is the heavily subsidised
unit cost of energy within the GCC.
“[A report by] the Abdullah Bin Hamad Al-
Attiyah Foundation for Energy & Sustainable Development in November 2015 states that this is as
much as 66 percent for some GCC countries.
“Given the promising development of low carbon infrastructural energy generation projects, the
hidden costs of subsidized energy are reducing. “Nonetheless, addressing this difference would
be the strongest incentive. Since utility costs are rising, a clear road map of future financial
impacts would further support this stimulus

Portugal to get US Cheniere LNG cargo
LNG World
Portugal is set to receive a cargo from Cheniere’s Sabine Pass LNG export terminal in Louisiana,
at least that is what the ship-tracking data currently shows. This would be the second U.S. LNG
cargo produced from shale gas to reach Portugal.
According to the shipping data by the port of Sines, the 162,000-cbm Golar Kelvin is expected to
arrive with a Sabine Pass cargo at the REN-operated Sines terminal on February 6.
The first U.S. LNG cargo to Portugal and to Europe landed in April last year onboard the MEGI-
powered LNG carrier, Creole Spirit. This cargo was purchased in the spot market by Portugal’s
Galp Energia.
LNG World News contacted Galp for a comment on the latest shipment. We will update the article
once we receive a response. Houston-based Cheniere started exporting LNG from Sabine Pass in
February last year, a major milestone in global LNG trade as the U.S. is set to become on of the
top exporters of the chilled fuel.
Previously, most of the Sabine Pass cargoes went to Latin America, however, this changed in
December when the majority of cargoes went to Asia, where cold winter temperatures increased
residential heating demand and rising spot LNG prices led to larger price spreads between the
Atlantic and Pacific basins.
In a recent report, Reuters said that U.S. LNG exporters have again shifted their focus, this time to
Southern Europe from Asia, as cold weather and problems with Algerian gas supply have driven
Europe’s gas prices higher.
The report noted that recently one Sabine Pass LNG cargo was delivered to Spain and one to
Turkey each, saying that more cargoes of the chilled fuel were heading to Europe.

NewBase 05 February 2017 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices settle the week WTI at $53.83, Brent at $ 56.80, after
US Treasury imposes sanctions on Iran
Oil prices gave up much of their gains after jumping on Friday as the United States imposed
sanctions on some Iranian individuals and entities, days after the White House put Tehran "on
notice" over a ballistic missile test.
Front month U.S. West Texas Intermediate crude futures settled 29 cents higher at $53.83 a
barrel. For the week, the contract was up about 1 percent. Brent crude futures were up 24 cents
at $56.80 a barrel by 2:34 p.m. ET (1934 GMT). Brent was on track to gain about 2 percent on the
week, its first significant weekly rise this year.
Volume in U.S. crude futures was relatively low on Friday, with about 335,000 contracts changing
hands by 12:15 p.m., on track to fall short of the 200-day moving average for 528,000 contracts.
This is the first move by the administration of President Donald Trump against Iran. It follows his
vows during the 2016 campaign to get tough on Tehran. Under the sanctions, announced by the
U.S. Treasury, 13 individuals and 12 entities cannot access the U.S. financial system or deal with
U.S. companies.
A senior U.S. administration said Friday's sanctions were an "initial step" in response to Iran's
"provocative behavior," suggesting more could follow if Tehran does not curb its ballistic missile
program and continues support for Houthi militia in Yemen.
The news added to volatility in what had already been a day of choppy trading. Analysts said the
market is torn between promised cuts from the Organization of the Petroleum Exporting
Countries and fears over rising U.S. shale oil production.
Oil price special
coverage

"While the market is taking these actions in stride so far as unlikely to result in a larger military
conflict that would put Persian Gulf crude oil supplies at risk, the odds of that scenario are
certainly higher than a week ago," wrote Timothy Evans, energy analyst at Citi Futures in New
York.
Trump had warned on Twitter that "Iran is playing with fire" after its missile test. "The
'trumperament' of the new U.S. president is being tested by Iran and soon maybe also by Russia
and China," said Olivier Jakob, managing director of consultancy PetroMatrix. "And that is addin
Comments by Russian energy minister Alexander Novak that oil producers had cut their output as
agreed under a deal with OPEC, also helped to support prices, analysts said.
Novak said that Russian companies might cut oil production more quickly than required by its deal
with late last year. He said that 1.4 million barrels per day (bpd) was cut from global oil output last
month as part of the deal.
Oilfield services firm Baker Hughes reported U.S. drillers added 17 oil rigs in the last week. The
count has been recovering since June and now stands at 583 rigs, compared with 467 rigs last
year.
Analysts said oil's advance could run out of steam quickly. PVM Oil Associates noted the market
"is sandwiched between supportive OPEC-led output cuts and the bearish impact of a resurgence
in U.S. crude production."
The prospect of more oil output from Nigeria and also from other non-OPEC producers such as
Brazil also looms. "Record speculative length threatens to trigger a sharp price fall as unease
builds amid the ongoing wait for a conclusive upside breakout," Commerzbank said in a note.
Futures climbed 0.5 percent in New York. The new restrictions were announced as President Donald Trump seeks to punish Tehran for its
ballistic missile program after warning the Islamic Republic that it’s “playing with fire.” The Organization of Petroleum Exporting
Countries cut output by 840,000 barrels a day last month, according to a Bloomberg survey.
After posting the biggest annual gain in seven years in 2016, oil has fluctuated in the mid-$50s in a tug of war between OPEC cuts and signs
of recovering U.S. output. While producers from Saudi Arabia to Angola have implemented cuts and Russia says it’s ahead of schedule with
its own reduction, wary investors are also considering that U.S. shale drillers are boosting activity.

ICE Hires Consultant to Review Brent Oil Prices Calculation
by Javier Blas and Laura Hurst
The exchange that’s home to Brent crude futures hired a consultant to discuss with traders, banks
and other market participants measures to revamp how North Sea oil prices are calculated.
Intercontinental Exchange Inc. hired Energex Partners, founded by former Morgan Stanley oil
traders, to discuss potential changes to the multi-layered North Sea market that includes both
physical and financial benchmarks. Given that such reviews are normally led by energy and
commodity price publisher S&P Global Platts, the move suggests ICE is taking a more proactive
role in shaping the mechanisms that underpin its biggest energy contract.
Brent crude futures compete with West Texas Intermediate as the world’s most-traded oil
contracts, with the equivalent of billions of barrels normally held at any one time. They’re also
intertwined with the work of Platts, whose daily assessments are used to benchmark millions of
barrels of trades every day. The publisher’s key North Sea price is based on four grades: Brent,
Forties, Oseberg and Ekofisk.
"The work we are doing with Energex Partners is forward looking and recognizes that the
benchmark needs to continue to evolve,” David Peniket, the president of ICE Futures Europe, said
in an interview. “Over time, this is likely to mean broadening out to bring in crude produced outside
the North Sea region.”
The hiring of a consultant to review the North Sea oil market comes at a time when Platts itself is already
talking to parts of the market about possible changes to its Dated Brent benchmark. Platts opened a formal
consultation last year on a proposal to add new grades to the Brent benchmark. The price assessment
agency was in particular considering the Norwegian Troll crude grade.
The future of the Brent contract will be a key topic of conversation this month during the annual
International Petroleum Week oil conference, that every year gathers thousands of traders, refiners,
bankers and others in London for talks.

Flood of light crude to Asia,push prices of regional grades lower
REUTERS/Thomas Peter
A flood of light crude oil set to arrive in Asia will likely push prices for regional grades lower,
crimping revenues and potentially creating a supply surplus since local refiners are ill-equipped to
process all of the flow.
Price differentials for Malaysian crude grades, particularly the light Kimanis grade, should decline
as a surge in cargoes from the United States and Europe is due in Asia in March and April, said
multiple traders who participate in the Asian regional crude market. Light crudes are grades with a
lower density and typically produce more gasoline and diesel fuel when refined.
BP and Trafigura are marketing at
least 3 million barrels of U.S. Eagle
Ford crude in Asia, three traders
said. From Europe, some 4 million
barrels of unsold North Sea Forties
crude are likely to arrive in Asia in
March or April, three trading sources
with knowledge of the matter said.
Glencore and Azerbaijan's Socar
each have 1 million barrels on hand,
while Trafigura was offering another
2 million barrels, they said.
A record 10 million barrels of North
Sea crude loaded in January for
Asia, close to a third of the region's total exports, Eikon data showed.
A narrowing in the price difference between Middle East benchmark Dubai and European
benchmark Brent and U.S. West Texas Intermediate oil has opened the arbitrage for the light oil to
come to Asia. Brent's premium to Dubai swaps averaged $1.64 per barrel in January, the lowest
since September 2015, data on Thomson Reuters Eikon showed.
"The overall Atlantic Basin arbs into Asia in Q1 are at the high (end) of historical ranges," said a
Singapore-based senior trader with an international oil company who declined to be named due to
company policy.
The premium for Malaysia's Kimanis for April-loading may fall to below $3.50 a barrel to
benchmark dated Brent prices from as much as $4 for March-loading supplies, said three traders
who participate in the market. "The arbitrage volumes will kill off Malaysian crude oil values," one
of the traders, based in Singapore, said on condition of anonymity.
The light oil from the U.S. and Europe is arriving at the same time that Saudi Arabia has boosted
light shipments to Asia to offset cuts in heavy crude to meet its commitments to the Organization
of the Petroleum Exporting Countries supply cuts.
Additionally, Abu Dhabi, part of the United Arab Emirates, has raised exports of its Murban light
grade after a refinery outage. Other light grades from the Mediterranean are set to come East as
well. At least half of the Azeri Light for February loading should sail to India, China, Vietnam and
Taiwan.

Shale Oil Makes $70 the New $100
By Liam Denning Rani Molla
This is not a chart that OPEC would like:
It shows Wood Mackenzie's projections of breakeven oil prices for new wells in North America's
shale basins and the Gulf of Mexico. The first thing to notice is that, on average, it makes sense
on paper to drill almost anywhere.
Reality is a bit more complicated. As we discussed in this earlier column, all-in costs for
exploration and production companies include things like general and administrative overhead and
interest charges, all of which must be borne by the barrels they produce. In addition,
transportation costs can vary widely depending on where you're drilling, where your refining
customers are and whether the oil is being shipped by pipeline, rail-car or truck.
So consider a driller in the Bakken with an average breakeven price of $52 a barrel. Add in, say,
$4 for overhead and interest charges and assume the oil is being sent from North Dakota to
refiners on the Gulf Coast by railroad at $12 a barrel. The all-in breakeven price for that barrel is
$68. If there's space on a pipeline available, then that comes down to maybe $63 (which is
why President Trump's push for new pipelines is welcomed particularly by inland drillers).
In contrast, drillers in the Wolfcamp basin -- part of the prolific Permian basin -- enjoy average
breakeven prices of about $42 to $43 a barrel on Wood Mackenzie's projections. Add in $4 of
overhead and interest but only $3 to ship the oil across Texas, and the all-in breakeven price is
about $50. No wonder the Permian shale is the hottest area for E&P investment.

Go back to the chart, and the other thing to notice is the wide range of breakeven prices. The
average for the shale basins is $32 a barrel. Not everyone gets those lower average economics.
Even if the message is a mixed one, though, it is still unwelcome to OPEC. Only a few years ago,
breakeven prices in shale basins were estimated to be north of $80 a barrel or, for some, $100.
On Wood MacKenzie's numbers, even the upper end of the range is now in the low $70s.
Even if suffering oilfield-services contractors demand higher fees and help raise those breakeven
prices some, OPEC's room to maneuver in using supply cuts to push prices higher has shrunk
significantly.
The short time that it takes to develop shale resources, relative to conventional oilfields, and the
E&P industry's ability to raise money on the back of promises of growth mean that pushing the
price too high could unleash another round of fighting for market share, just as we've seen these
past two years.
And this time, that danger zone isn't $100-plus, but more like $60 or $70-plus. Oil bulls watching
today's spot price of $54 may well think that's just fine -- although that would ignore the inherent
volatility of a scenario where shale and OPEC are battling it out.
As for many of OPEC's members, their economies just aren't built to survive on the prospect of
(maybe) $70 a barrel. Therein lies a real wildcard in the years to come.
It’s ambitious to think that oil prices could reach $65: IEA
Silvia Amaro | @Silvia_Amaro
Despite a recent OPEC agreement to cut oil production and boost prices, it is unrealistic to expect
that the commodity will reach $65 a barrel in the near term, an analyst at the Paris-based
International Energy Agency told CNBC.
OPEC countries
reached an agreement
last November to cut
production by 1.2
million barrels per day
to support oil prices
and tackle three-
consecutive years of
falling investment. In
early December, some
non-OPEC countries,
such as Russia, joined
their efforts and
promised to cut output
by 600,000 barrels per
day.

"I think 63, 65 (dollars a barrel for Brent) I think you might be a little bit ambitious there because
the OPEC producers have got this basic issue, they don't want the price to go too low clearly,
because their economies wouldn't stand it," Neil Atkinson, head of the oil industry and markets
division, at the IEA told CNBC Friday.
"But if the price goes too high then that's going to attract a lot of investment in other parts of the
world, principally the U.S. shale producers," Atkinson added.
The six-month agreement had its first test in January. Analysts are watching closely whether
OPEC and non-OPEC members stick to their commitments. A large number of oil experts do not
expect 100 percent compliance.
According to Atkinson, so far, "they're doing quite well."
"The signs are quite encouraging that production has been cut back quite significantly in January,"
he added.
A Reuters survey, published this week, showed at the end of January OPEC members cut
production by 958,000 barrels per day, equating to an 82 percent compliance of what they initially
pledged.
Brent crude was trading at $56.94 a barrel on Friday morning, while WTI was being sold at $53.95
a barrel.
Silvia Amaro
NewBase Special Coverage
News Agencies News Release 05 Feb. 2017
Why US Congress just killed a rule restricting coal companies
from dumping waste in streams
Brad Plumer VOX
With everything that Republicans want to do — repeal Obamacare, overhaul the tax code — it
might seem odd that one of Congress' very first acts would be to kill an obscure Obama-era
regulation that restricts coal companies from dumping mining waste into streams and waterways.
But that is indeed what's going on. On Thursday, the Senate voted 54-45 to repeal the so-called
"stream protection rule" — using a regulation-killing tool known as the Congressional Review Act.
The House took a similar vote yesterday, and if President Trump agrees, the stream protection
rule will be dead. Coal companies will now have a freer hand in dumping mining debris in streams.

Killing this regulation won't really help Trump fulfill his goal of reversing the coal industry's decline;
that decline has more to do with cheap natural gas than anything else. Instead, Republicans are
mostly focusing on this rule because they can. Because the stream protection rule wasn't finished
until very late in 2016, it's much, much easier to kill than most of the other Obama-era rules
around coal pollution. It was an easy target, so long as the GOP acted fast.
What Obama’s 'stream protection rule' actually does
Coal mining is a messy business. In parts of West Virginia, Kentucky, and Virginia, for instance,
mining companies often get at underground coal seams by blowing up the tops of mountains — a
process known as mountaintop removal mining. Once that's done, they'll frequently dump the
debris into the valleys below, which can contaminate streams and waterways with toxic heavy
metals.
Appalachian Voices, an environmental
group, estimates that coal companies have
buried over 2,000 miles of streams in the
region through mountaintop removal
mining. And studies have found that when
this all debris and waste gets into water
supplies, it can have dire health impacts for
the people living nearby.

In theory, there's a law to mitigate this. The 1977 Surface Mining Control and Reclamation Act
says that companies should not cause "material damage to the environment to the extent that it is
technologically and economically feasible." But that language is awfully vague. And the agency
responsible for enforcing this law, the Office of Surface Mining Reclamation and Enforcement
(OSMRE), hasn't clarified what this language means since publishing a "stream buffer rule" in
1983.
"The rule doesn’t address all the problems with the most destructive mining practices. But it
makes it a little bit harder for coal companies to pollute streams. And it makes it a little easier for
communities to fight back against mines if they don’t want them."
In theory, there's a law to mitigate this. The 1977 Surface Mining Control and Reclamation Act
says that companies should not cause "material damage to the environment to the extent that it is
technologically and economically feasible." But that language is awfully vague. And the agency
responsible for enforcing this law, the Office of Surface Mining Reclamation and Enforcement
(OSMRE), hasn't clarified what this language means since publishing a "stream buffer rule" in
1983.
Community groups and environmentalists had long pushed to update the regulations here,
especially since mining practices have changed dramatically over the past three decades and
scientists have learned more about the harmful effects of water pollution from coal mining. In
2008, the George W. Bush administration published an update to the "stream buffer rule," but
those efforts later got struck down in court for running afoul of the Endangered Species Act.
So enter the Obama administration. Ever since 2009, OSMRE has been trying to update its
guidance here. That process involved poring through reams of research on the effects of coal
mining on ecosystems, holding endless hearings, talking to various stakeholders, and so on.
The final rule got published on December 19, 2016 — just before Obama left office. And while it's
incredibly complex, updating hundreds of older regulations, it basically puts a couple of key
restrictions in place for coal companies seeking permits to expand or start new mines in the future:
1. First, a company that wants to open either a surface or underground mine needs to avoid
causing damage to the "hydrologic balance" of waterways outside of its permit area. The
rule goes into excruciating detail on what these definitions mean, but it's basically a much
stricter limit on dumping waste and debris in surrounding ecosystems.
2. Second, companies and regulators have to do a baseline assessment of what nearby
ecosystems look like before any new mining begins. They then have to monitor affected
streams during mining, and the company has to develop a plan for restoring damaged
waterways to something close to their natural state after mining is done.
This sounds pretty basic, but there were numerous debates over best how to define "hydrologic
balance," how exactly to monitor waterways, how to deal with the variety of coal industry practices
out there, and so on.
In the end, environmentalists certainly weren't thrilled with the rule — many groups didn't think it
went far enough to restrict the dumping of debris, and they don't believe coal companies can
restore damaged streams fully to their prior state after mining. But on balance, they thought the

rule an improvement over the status quo. OSMRE estimated that it would protect an additional
6,000 miles of streams and 52,000 acres of forest.
"The rule doesn't address all the problems with the most destructive mining practices," says Thom
Kay of Appalachian Voices. "But it makes it a little bit harder for coal companies to pollute
streams. And it makes it a little easier for communities to fight back against mines if they don't
want them."
How the stream protection rule became so controversial
But coal companies absolutely loathe this new rule. Coal mining is already facing a brutal decline
in Appalachia — partly because the industry is moving West to places like Wyoming, but also
because the advent of cheap natural gas has absolutely crushed US demand for coal, causing
hundreds of coal power plants to close nationwide. Now miners have to deal with this rule, which
imposes new restrictions and makes it more expensive to operate.
The National Mining Association, an industry trade group, says the stream-protection rule could
put more than half of the nation's yet-untapped coal reserves off limits to future mining — further
crippling a wounded industry. The group would prefer environmental protections be handled at the
state level (where, in states like West Virginia and Kentucky, regulators have a much lighter
tough). "It's a pure expression of all that ordinary Americans loathe about rule by bureaucracy,"
writes NMA's Luke Popovich.
Other coal companies, like Ohio-based Murray Energy, complained that the rule could outlaw
favorite techniques like longwall mining — which involves using machines with revolving blades to
cut coal from an underground seam into slices. "This unlawful and destructive rule is nothing but a
thinly veiled attempt to destroy our nation's underground coal mines and put our nation's coal
miners out of work," said Robert Murray, the CEO of Murray Energy, after the rule was finished.
OSMRE, for its part, had argued that these worries were (mostly) overblown. The agency pointed
out, for instance, that most longwall operations are so deep underground that they wouldn't have
much effect on streams above — and
hence are unlikely to be affected by the
regulations. But the agency did agree that
the rule would impose some costs, and
it'd likely make certain mining plans
uneconomic at the margins.
Environmental protection isn't free.
Whatever the precise economic impact,
the rule has taken on a life of its own in
American politics. On the campaign trail,
Donald Trump talked about reviving
America's coal industry and ending
Obama's "war on coal," blaming rules like
this for the industry's decline. After the
election, Robert Murray — one of Trump's
staunchest supporters — talked about

killing the stream protection rule as a top priority. The rule featured prominently on Trump's
transition website.
Why it was so easy for Republicans to kill this particular rule
Now, the stream protection rule was hardly the only environmental regulation that the Obama
administration slapped on the coal industry. The Environmental Protection Agency has taken
sweeping steps to cut air pollution from coal power plants, adding to the industry's woes
(especially when cleaner natural gas is so cheap and plentiful).
Trump would love to overturn many those other rules as well. The trouble is that most of them are
hard to repeal. He'd have to go through the EPA's rule-making process, which would take years
and could be thwarted by lawsuits from environmental groups.
But the stream protection rule was different. Because it took so long to complete, and because it
was only finalized in December 2016, it can be easily overturned in the new Congress via the
Congressional Review Act (CRA).
The CRA basically says the House and Senate can kill any recently finalized regulation with
simple majority votes in both chambers — so long as the president agrees. What counts as
"recently finalized" gets complicated and involves counting "legislative days," but Congress can
basically vote to overturn any Obama-era regulation that was finished after mid-June 2016 — a list
that spans more than 50 major regulations.
The stream protection rule happens to be the one big coal rule vulnerable to the CRA. It's not the
biggest problem facing the coal industry, or even the most far-reaching environmental policy
around. But it's procedurally simple to repeal, and Democrats in the Senate can't filibuster CRA
votes. As long as Republicans moved quickly before the CRA window closed, they could nix it
quickly and easily. So that was that. Mining waste became one of the first orders of business in
the new Congress.
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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
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Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility &
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