New base 991 special 24 january 2017 energy news

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NewBase 24 January 2017 - Issue No. 991 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 Barakah nuclear power plant operating by this May 2017
The National - Caline Malek
The UAE’s first nuclear power plant could begin operating by May after the industry’s regulator on
Sunday approved licences to transport and store nuclear fuel – a final step in a long, careful
process.
The Federal Authority for Nuclear Regulation said the fuel’s first shipment would be sent from
South Korea in coming weeks before being taken to the power plant’s Barakah site in the Western
Region next month.
The authority’s approval is considered to be the last step before the first nuclear reactor becomes
operational in May, pending regulatory approval.
Christer Viktorsson, Fanr’s director general, said it was a "major milestone for us because we’ve
worked diligently during months to make us convinced that everything is ready to transport and
store fuel".

"One of the principles of the UAE’s nuclear power programme is operational transparency," Mr
Viktorsson said. "This is an effort by Fanr to keep the public informed about the important
decisions it is making."
The first shipment will be sent by sea and inspected on arrival in a couple of weeks, before it is
moved to the reactor’s storage. "They are packing the fuel now in Korea and we had inspectors
there a few weeks ago," said Ian Grant, the authority’s deputy director general for operations.
Mr Grant said the plant’s operator, the Emirates Nuclear Energy Corporation, already had power
in the plant and was running systems at the plant to check its equipment. "Once we have
authorisation to load the fuel, there would be a period of about another six or seven months of
testing and gradually increasing power," he said.
Unit 1 of the plant will initially operate on low power as part the trial, going through phases of
shutting down and increasing its power gradually until it reaches full power, also known as
commercial operation, which will then feed power to the grid.
"The current schedule is May but we’re not bound by that schedule," said Mr Grant. "We expect
further inspections from the International Atomic Energy Agency, which will make sure the fuel is
used for peaceful purposes only."
Hamad Alkaabi, UAE ambassador to the IAEA, agreed that receiving fuel was a significant
milestone.
"The UAE has worked closely with the IAEA safeguards teams to ensure all surveillance and
control measures are in place and in line with IAEA requirements at the Barakah nuclear plant,"
Mr Alkaabi said.
"This step demonstrates that all arrangements and measures in terms of readiness, safety and
security have been received and confirmed to be adequate." More than 200 experts work in Fanr
in nuclear safety, security, radiation protection, safeguards and related areas such as emergency
preparedness and waste management.
The plant is designed on Korea’s model, which is set to withstand major natural disasters.
"The Korean Peninsula has got stronger earthquakes than here so the Korean design is very
robust against earthquakes," Mr Grant said. "It is designed to withstand twice the might that is
predicted to happen at the site and we’ve studied the earthquake design extensively."
Mr Viktorsson said the public seemed to be in favour of the nuclear power plant. "When we’re out
talking to the public in forums, the support for nuclear power in this country is much higher than
what I am used to," he said.
"So it seems there is confidence in the leadership that this energy source is safe, secure and
peaceful. That’s why so much responsibility is on us because we have to ensure all this and take
the time it needs."

Saudi Aramco tax will be cut to lure investors to IPO: CEO
Bloomberg/Davos
Saudi Arabia has promised it will reduce the overall tax rate paid by its national oil company to
make its 2018 initial public offering – potentially one of the largest in history – more appealing to
investors.
“Definitely the fiscal regime will be changed,” Saudi Arabian Oil Co chief executive officer Amin
Nasser said in a Bloomberg Television interview last
week in Davos, Switzerland. “When you look at the fiscal
regime and the taxes, it has to be aligned with other listed
companies.”
Aramco, as the company is commonly known, currently
pays a 20% royalty on its revenue plus an 85% tax on
income, Nasser said. He declined to say what tax rate the
kingdom is considering.
Saudi officials said Aramco’s tax rate wouldn’t need to be
slashed because the company - considered the crown
jewel of the country’s economy - is able to make a profit even when oil prices plunge. In 2016,
under the existing tax regime and with crude dipping to 12-year lows, Aramco was able to pay a
dividend and fund its biggest-ever capital investment program, Nasser said.
“Based on the advice of the different banks that we use during the process of the IPO, we are
setting a certain fiscal regime that will meet investors’ requirements,” Nasser said.
Saudi Arabia is looking at markets including Hong Kong, London, New York and possibly even
Canada as international venues for the sale. The kingdom will offer 5% of the world’s biggest oil
producer as part of a plan by Deputy Crown Prince Mohammed bin Salman to set up a giant
biggest sovereign wealth fund and help reduce the economy’s reliance on hydrocarbons.
Nasser said the kingdom was considering whether to do a double listing, with shares sold in the
domestic market in Riyadh and a foreign exchange, or a triple-listing, with two foreign locations on
top of the local bourse.
In his most extensive comments yet about the IPO plans, Nasser said the Aramco IPO will include
the so-called concession, which comprises the oil and gas reserves of the kingdom. Saudi Arabia
sits on almost a fifth of the oil world’s reserves.
“The listing is based on Saudi Aramco maintaining the concession,” Nasser said. “If you have the
concession, you have the physical oil.”
Nasser said the IPO will take most likely take place in the second half of 2018, narrowing the
window from earlier comments by Saudi officials who said a flotation was planned for some point
through 2018.
In the past, Saudi officials have said the flotation would value the company at as much as $2tn –
which, if true, will make it the world’s most valuable. Selling just 5% could raise $100bn, ranking it
as the biggest ever IPO.
However, some investors have cautioned that Aramco is unlikely to be worth as much, noting that
other national oil companies that have sold shares have achieved relatively low valuations.

Nasser said that Aramco wasn’t planning as yet to increase its production capacity, currently at
about 12mn bpd, saying the matter would be decided after the IPO. The company has “ample”
spare capacity to meet any incremental demand, he added.
Instead, Nasser said the focus is in expanding the company’s refining capacity to 8mn to 10mn
bpd, up from 5.4mn bpd currently. Saudi Arabia invested in the 1980s in refineries in the US and
more recently has been spending money in South Korea and Indonesia.
“This is an area of interest for us: Expand our refining capacity globally and also our
petrochemicals,” he said. The IPO is the cornerstone of a much wider and ambitious plan to re-
tool the Saudi economy, called Vision 2030, expanding the non-energy sector.
“We will like to have less reliance on the hydrocarbons,” said Nasser, who was appointed CEO in
2015 and climbed the ladder after starting 1982 as graduate in oil engineering from the King Fahd
University.
Still, Nasser insisted that Saudi Arabia wasn’t turning its back on hydrocarbons. “The kingdom is
trying to diversify – at the same time, we are retaining our strength in oil and gas and expanding
it,” he said.

Kuwait oil emergency over oil leak on shore later contained
* Associated Press
Kuwait’s national oil company has declared a state of emergency following an oil leak in one of its
southwestern fields. Monday’s statement by the Kuwait Oil Company did not identify the onshore
field affected by the leak, which began on Sunday.
The state-run Kuwait News Agency said the leak hit the al-Maqwa field. The company said there
was no sign of a toxic gas leak. It provided no details about how many barrels of oil had been
spilled.
Kuwait's national oil company says it has contained an oil leak at one of its southwestern oil fields.
Monday's statement by the Kuwait Oil Co. did not identify the onshore oil field affected by the leak,
which began Sunday.
The state-run Kuwait News Agency said the leak hit the al-Maqwa field. It offered no details about
how many barrels of oil had been spilled. OPEC member Kuwait is a major oil producer. The U.S.
Energy Information Administration says Kuwait produces some 2.7 million barrels of crude oil a
day and holds the world's sixth-largest oil reserves.
In August, Kuwait announced a spill at its Ahmadi field. A February fire struck another oil well after
a spill. A 2015 fire at a workers residence at al-Maqwa injured three people.
Opec member Kuwait is a major oil producer. The US Energy Information Administration said
Kuwait produces about 2.7 million barrels of crude oil a day and holds the world’s sixth-largest oil
reserves. In August, Kuwait announced a spill at its Ahmadi field. A February fire struck another
oil well after a spill.

Russian Gazprom mulls $6 billion asset sales, dividend freeze
Gazprom needs to increase borrowing to ‘ensure liquidity and cover obligations’
Bloomberg
Gazprom PJSC, the world’s biggest natural gas producer, is considering asset sales, freezing
dividends and increasing its borrowing as export earnings wane, according to its three-year
budget.
The Russian state-controlled company aims to raise 350 billion roubles (around $6 billion) from
asset sales this year, while borrowing may climb to 288 billion roubles and more than double from
that level next year, a copy of the document obtained by Bloomberg News show. Dividend
payments are forecast at the 2016 level through 2019, according to the plan, approved by the
board in December.
Despite a rebound in crude oil, which dictates the price for most of Gazprom’s export contracts,
the proposed budget shows the company remains under financial pressure as it tries to finance
new pipelines to Europe and Asia. Gazprom needs to increase borrowing to “ensure liquidity and
cover obligations” at oil prices close to current levels, according to the budget.
No final decision has been made on asset sales and there is no set time frame, two people with
knowledge of the issue said, asking not to be identified because the information isn’t public.
Gazprom’s press service declined to comment. The stock lost as much as 1.7 per cent in Moscow
to the lowest intraday level since Nov. 18.
Management plans to sell Gazprom’s stake in Gascade Gastransport GmbH, which operates
more than 2,400 kilometres of gas pipelines across Germany, possibly this year, Interfax reported,
citing unidentified people. There are several potential bidders, the newswire said. The Moscow-
based exporter acquired 49.98 per cent in the grid through an asset swap with Germany’s BASF
SE in 2015.
Gazprom hasn’t sold such a large amount of assets since 2010. Back then, it disposed of 9.4 per
cent of its largest domestic competitor, Novatek PJSC, for 57.5 billion roubles (about $1.9 billion at
the time), classifying its remaining 9.9 per cent stake as an asset for sale. The shares, which
currently have a market value of about 215 billion roubles based on Moscow trading, could be a
candidate, said Raiffeisen Centrobank AG analyst Andrey Polischuk.
GROWING THE VALUE OF GAS TRANSPORTATION ASSETS

US oil & Gas Industeries - Robots Are Taking Over Oil Rigs
Bloomberg - David Wethe
The robot on an oil drillship in the Gulf of Mexico made it easier for Mark Rodgers to do his job
stringing together heavy, dirty pipes. It could also be a reason he’s not working there today.
The Iron Roughneck, made by National Oilwell Varco Inc., automates the repetitive and
dangerous task of connecting hundreds of segments of drill pipe as they’re shoved through miles
of ocean water and oil-bearing rock. The machine has also cut to two from three the need for
roustabouts, estimates Rodgers, who took a job repairing appliances after being laid off
from Transocean Ltd.
“I’d love to go back offshore,” he says. The odds are against him. As the global oil industry begins
to climb out of a collapse that took 440,000 jobs, anywhere from a third to half may never come
back. A combination of more efficient drilling rigs and increased automation is reducing the need
for field hands. And therein lies a warning to U.S. President Donald Trump, who has predicted a
flood of new energy-sector jobs under his watch.
Automation, of course, has revolutionized many industries, from auto manufacturing to food and
clothing makers. Energy companies, which rely on large, complex equipment for drilling and
maintaining oil wells, are particularly well-positioned to benefit, says Dennis Yang, chief executive

officer of Udemy, a company in San Francisco that trains workers whose careers were derailed by
advanced machinery.
“It used to be you had a toolbox full of wrenches and tubing benders,” says Donald McLain,
chairman of the industrial-programs department at Victoria College in south Texas. “Now your
main tool is a laptop.” McLain, who worked as a rig hand for 25 years, is helping to retrain laid-off
oil workers for more technical jobs.
Dangerous Talk
During the boom, companies were too busy pumping oil and gas to worry about head count, says
James West, an analyst at investment bank Evercore ISI: “We got fat and bloated.” He says the
two-and-a-half-year downturn gave executives time to rethink the mix of human labor and
automated machinery in the oil fields.
Still, in the current political climate, they’re proceeding cautiously. More robotic drilling
ultimately means lower labor costs and fewer workers near some of the most dangerous tasks.
But oil companies probably will frame their cost-cutting technologies simply as a way to be more
competitive around the world, says West.
“They’ll more likely brag about the automation rather than these head counts,” West says. “It’s
kind of dangerous to talk about jobs in the Trump administration.”

Yet Trump is seen as the great hope for more shale-job creation than ever before, says Jay
Colquitt, founder of OilfieldTrash.com, an online news portal catering to oilfield workers. As more
federal lands open up for drilling, the jobs will follow, he adds.
“Even though modern technology is great, you can’t eliminate the person,” says Rodgers. “To
make sure it never fails, you’ve got to have somebody there watching it, to verify it.”
The industry is acutely aware of the heavy reliance on manpower, after the world’s four largest oil-
service companies spent $3.12 billion in severance costs during the past two years, says Art
Soucy, president of global products and technology for Baker Hughes.
Rigs have gotten so much more efficient that the shale industry can use about half as many as it
did at the height of the boom in 2014 to suck the same amount of oil out of the ground, says Angie
Sedita, an analyst at UBS Corp. Nabors Industries, the world’s largest onshore driller, says it
expects to cut the number of workers at each well site eventually to about five from 20 by
deploying more automated drilling rigs.
The impact of technology extends well beyond the wellhead. Automation-related jobs for software
specialists and data technicians are in demand as the oil industry recovers, said Janette Marx,
chief operating officer of Airswift, an oilfield recruiter. She sees explorers and service companies
being much more methodical and selective in their hiring this time around.
“To me, it’s not just about automating the rig,
it’s about automating everything upstream of
the rig,” says Ahmed Hashmi, head of
upstream technology for BP PLC. “The
biggest thing will be the systems.”
That means an engineer can design an oil
well at his desk. With the press of a button, an
automated system would identify the
equipment needed from a supplier, create a
3D model and send instructions for building it
out into the field, Hashmi says. “That is
automation.”

Natural gas prices in 2017 and 2018 are expected to be higher
than last year.. Source: U.S. Energy Information Administration, Short-Term Energy Outlook
In its January 2017 Short-Term Energy Outlook (STEO), EIA expects the Henry Hub natural gas
spot price to average $3.55 per million British thermal units (MMBtu) in 2017 and $3.73/MMBtu in
2018, both higher than the 2016 average of $2.51/MMBtu. Higher prices in 2017 and 2018 reflect
natural gas consumption and exports exceeding supply and imports, leading to lower average
inventory levels.
The confidence interval range for natural gas prices is a market-derived range that reflects trading
in New York Mercantile Exchange (NYMEX) futures markets and is not directly based on EIA's
supply and demand estimates. The values for the upper confidence interval increase during the
winter months compared with the rest of the year, which reflects the higher probability of an
increase in natural gas consumption for space heating use as a result of colder weather. By
February 2018, the 95% confidence interval ranges from $1.78/MMBtu to $7.22/MMBtu.

In 2016, the annual average Henry Hub natural gas price was the lowest since 1999 as a result of
a very mild winter that left natural gas inventories at a record high for the end of March.
However, high natural gas use for electricity generation during the summer and declining
production contributed to Henry Hub natural gas prices rising from an average of $2.00/MMBtu in
the first quarter of 2016 to an average of $2.88/MMBtu in the third quarter of 2016.
Cold weather across much of the northern United States in mid-December led to an increase in
demand for space heating (much of which is provided by natural gas), contributing to natural gas
inventories ending the month below the five-year average. As a result, Henry Hub spot prices
increased to a monthly average of $3.59/MMBtu in December, the first month in which prices
averaged above $3.00/MMBtu since December 2014.
In 2017, Henry Hub prices are expected to remain near the levels in December 2016, leaving
annual average prices in 2017 higher than those in 2016. Prices are expected to be higher again
in 2018. The higher prices are the result of forecasted consumption and exports exceeding
forecasted production and imports, which implies that the difference will be supplied from
inventories. Because natural gas use for space heating in the residential and commercial sectors
depends significantly on winter weather, any significant discrepancy between weather
assumptions used in the forecast and actual weather could significantly affect both consumption
and prices.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook

EIA expects natural gas consumption to be higher in 2017 and 2018 than in 2016, based on a
return to more typical winter temperatures. In 2017, use of natural gas for electric power
generation is expected to decline from the record level in 2016 because of higher natural gas
prices. Natural gas-fired power generation is forecast to rise in 2018 because of overall growth in
electricity generation, but it is expected to remain below the 2016 level.
After declining in 2016 for the first time since 2005, dry natural gas production is forecast to
increase in both 2017 and 2018. The return to increasing production reflects a forecast of higher
Henry Hub natural gas spot prices as well as pipeline infrastructure buildout, particularly in the
Marcellus and Utica natural gas producing regions in and around Ohio and Pennsylvania.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
Natural gas exports are also expected to increase. Export growth in 2017 largely
reflects additional capacity coming online at Cheniere’s Sabine Pass liquefied natural gas (LNG)
liquefaction plant in Louisiana.
The 2018 growth is driven by the expected start of Cove Point LNG in Maryland in December
2017 and new projects at Cameron LNG and Freeport LNG on the U.S. Gulf Coast during the
second half of 2018. A small increase in pipeline exports to Mexico is expected in both years.
Imports of natural gas are expected to remain relatively stable over the forecast period at slightly
more than 8 Bcf/d. With expected growth in exports and stable import levels, the United States is
expected to become a net exporter of natural gas on an annual basis in 2018.

NewBase 24 January 2017 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices rebound on weaker dollar, production cuts
Oil climbed on Tuesday as a weaker U.S. dollar and production cuts announced by OPEC and
other producers buoyed the market, but an increase in drilling activity in the United States is likely
to keep a lid on prices.
Brent crude LCOc1, the international benchmark for oil prices, rose 30 cents to $55.53 a barrel by
0147 GMT. U.S. West Texas Intermediate (WTI) crude futures CLc1 added 27 cents to $53.02 a
barrel.
The dollar wallowed near seven-week lows, pressured by concerns about the impact of U.S.
President Donald Trump's protectionist trade stance.[USD/]
A weaker dollar makes greenback-priced commodities cheaper for importers holding other
currencies.
Ministers representing members of the Organization of the Petroleum Exporting Countries and
non-OPEC producers said at a meeting in Vienna on Sunday that of the almost 1.8 million barrels
per day (bpd) they had agreed to remove from the market starting on Jan. 1, 1.5 million bpd had
already been cut.
Bernstein Energy said global oil inventories declined by 24 million barrels to 5.7 billion barrels in
the fourth quarter of last year from the previous quarter. Still, this amounts to about 60 days of
world oil consumption.
Oil price special
coverage

"This is the biggest quarterly decline since the fourth quarter of 2013, confirming that
inventory builds are now reversing as the market shifts from oversupply to undersupply," it said in
a note.
Iraq's oil minister said on Monday that most oil majors working on its territory were participating in
oil output reductions agreed as part of the deal.
The reduction in supply by oil majors is being offset by an increase in U.S. production.
U.S. drillers added the most rigs in nearly four years, data from energy services company Baker
Hughes showed on Friday, extending an eight-month drilling recovery.
The country's oil production has risen by more than 6 percent since mid-2016, though it remains 7
percent below the 2015 peak. It is back to levels seen in late 2014, when strong U.S. crude output
contributed to a crash in oil prices.
Fawad Razaqzada, an analyst for Forex.com, said it could take a while before the impact of higher
U.S. production is felt in the market.
"Shale producers may allow the oil market to fully rebalance before increasing production once
again," he said.
Clarifying Opec’s production ceiling agreement
Oman Observer in Business
The oil market is well aware that Opec set a production ceiling at its meeting on November 30th
of 32.5 million barrels per day. But based on comments to a recent article I wrote, there is a lot of
confusion about how that ceiling applies.
A news story said, “Opec production dropped to 33.09 million barrels per day in December from
34.2 the previous month.” This is a misunderstanding of the situation. In particular, there is an
issue about Indonesia. At the meeting, this member decided to suspend its membership in Opec.
As Opec’s only net importer of oil, it could not agree to join the group in agreeing to limit its
output, which is understandable. It could have signed the agreement anyway, as I believe some
countries may have, not intending to honour the agreement, but it did not. To me, that reflects
integrity.
But less than two months later, there is confusion about the ceiling. To clarify, Opec included
Indonesia’s production in the ceiling, even though it had suspended its membership in Opec. I
suppose that happened because the deal was negotiated on the day of the meeting, and there
was a certain amount of chaos.
“Indonesia is in it, at the October level.” According to Opec’s December Monthly Oil Market
Report, Indonesia’s production level was 750,000 b/d. In Opec’s most recent MOMR, Opec
reported its production at 33.085 million barrels per day. But Indonesia’s production is no longer
included.
One might get the impression that Opec’s production is getting closer to its 32.5 ceiling. But if
Indonesia’s production is included, estimated to be 730,000 b/d by the Energy Information
Administration (EIA), then the Opec-14 actually produced 33.8 in December.
If Opec is going to quote its output without Indonesia, which seems appropriate, it should clarify
its ceiling without Indonesia. And that would be 32.5 minus 0.7, which is 31.8. And so the
December volume is actually 1.3 million barrels above that ceiling.

Why Saudi Arabia May Unravel OPEC's Big Deal
By Julian Lee
Saudi Arabia's oil minister Khalid Al-Falih says it may not be necessary to extend the deal reached
by the group and some non-member nations to cut oil supply by around 1.8 million barrels a day
beyond its initial six months, and that doing so could create a shortage. That seems a very quick
and painless solution to an oversupply problem that has bedeviled the oil market for the past two
years, brought several producers to the brink of collapse and tipped others over it.
It took a lot for the Saudis to agree to this deal in November, but the rationale seemed at least to
make sense. Brimming supply had created financial difficulties for the kingdom, and also
complicated the forthcoming IPO of a small part of Saudi Aramco.
Saudi Crude Exports
Crude oil exports hit a 13-year high in November, as OPEC met to agree output cuts
The latest numbers from the Joint Organisations Data Initiative offer a different, and compelling,
narrative. It turns out that, as the deal was being thrashed out, Saudi Arabia was enjoying a 35-
year high in total oil exports.
One big factor was a huge drop in the amount of oil the country needs to burn to generate
electricity. The punishing Saudi summers boost demand for electricity -- mostly to run air-
conditioners -- to a level that previously required vast amounts of oil-fired generating capacity to

be brought into use. The direct burning of crude oil in power stations would roughly double to
about 900,000 barrels a day at the height of the season.
Burning Crude
Saudi oil usage has dropped as natural gas replaces around a third of what it uses for power
generation
But that changed last year. The start-up of the Wasit gas plant allowed the kingdom to slash the
use of crude in power generation by as much as a third -- freeing that oil up for export. In addition,
the kingdom cut fuel subsidies, pushing down oil consumption by 2 percent year-on-year in the
first eleven months of 2016. That's the first dip since at least 2003, when JODI records begin.
This left Saudi Arabia with an embarrassment of riches as the OPEC negotiations were underway
last year. Unless it cut output, it would start flooding the market during the first half of 2017. The
stars were aligned for it to solve the problem by persuading others to share the burden in a way
that has not been seen since the financial crisis of 2008, while at the same time restoring its
credentials as a team player within OPEC.
DEMAND CONTRACTION
We really don't know, and never will, what the true Saudi motivation for agreeing to production
cuts was or is. But this new read on the Saudis' motivations for agreeing to the deal has the
benefit of explaining why Al-Falih is looking for a six-month time line and why the kingdom has
been prepared to make such a deep cut in its production. Its surplus will have disappeared by that
time, at which point it can start to boost production again in order to get exports back to the level it
wants to maintain.

Such a move could easily be the catalyst for the whole deal to fall apart by June. And there's no
way the global backlog of inventory will be dealt with at that time. This seems a situation designed
to antagonize the rest of the group and create a raft of bad feeling.
If maintaining exports is more important to Saudi Arabia than balancing the market, then so is a
willingness to back out on a hard-won deal that took the kingdom and its partners a lot of political
capital to achieve.

NewBase Special Coverage
News Agencies News Release 24 Jan. 2017
Bahrain Nogaholding marks close of $741m LNG terminal financing
NOGAS
Nogaholding, the investment and business development arm of Bahrain’s National Oil and Gas
Authority (Noga), has marked the financial close of its LNG Terminal Project with Bahrain LNG,
the developer and owner of the first LNG receiving and regasification terminal to be developed on
a PPP basis in the Middle East.
Held under the patronage of Shaikh Mohamed bin Khalifa bin Ahmed Al Khalifa, the Minister of
Oil, the dinner was hosted at the Four Seasons Hotel, Bahrain Bay.
More than 150 guests attended including representatives from the management of the consortium,
participating banks, members of the board of Bahrain LNG WLL, as well as senior management of
nogaholding, and members of the press.
Jointly owned by the Oil and Gas Holding Company (nogaholding – 30 per cent) and a consortium
consisting of Teekay LNG Partners LP (30pc), Gulf Investment Corporation (24.5pc) and
Samsung C&T (16.5pc), the Bahrain LNG Terminal is a key component of the further expansion of
the energy and related sectors of the kingdom.
Shaikh Mohamed said in his speech: “The security and reliability of our gas supply is very
important to us. The importance of Noga providing reliable and economic supplies of gas gave us
a strong incentive to develop the LNG import terminal as a means of accessing the booming and
increasingly competitive international LNG markets.”
Dr Dafer Al Jalahma, CEO of nogaholding, said: “We are incredibly proud of this significant
milestone achievement. I would like to thank the partners of the consortium, Korea Trade
Insurance Corporation (K-SURE) and the lending banks for making this financing a great success.
Against the backdrop of current economic market conditions, we are pleased to have successfully
sourced finance for the project of this size and complexity.”
“Led by K-SURE, this well-structured LNG regasification terminal transaction attracted high quality
project finance lending of $741 million for a tenor of 20 years. This reflects their confidence in
investing in Bahrain and further fueling growth of the energy development projects in the country.”

The LNG Terminal will comprise a Floating Storage Unit (FSU), an offshore LNG receiving jetty
and breakwater, an adjacent regasification platform, a subsea gas pipeline from the platform to
shore, an onshore gas pipeline and gas receiving facility, and an onshore nitrogen production
facility. The project will supplement local gas production to meet peak seasonal gas demand,
industrial growth and procure internationally-traded LNG on a competitive basis. It is due for
completion in early 2019 and will have a capacity of 800 million standard cubic feet per day.
It will be owned and operated under a 20-year agreement by Bahrain LNG. GS Engineering and
Construction was awarded the EPC contract. Teekay LNG will supply the Floating Storage Unit
(FSU) which will be modified specifically for this project, through a 20-year time-charter
agreement.
For this project, K-SURE will provide commercial and political risk cover for approximately 80 per
cent of the financing. Standard Chartered Bank, Arab Petroleum Investments Corporation
(Apicorp), and the Korea Development Bank acted as lead arrangers.
A syndicate of nine international and regional banks is participating to fund this project. The
banks include: Apicorp, Standard Chartered Bank DIFC, Korea Development Bank, Ahli United
Bank, Banco Santander, Crédit Agricole Corporate and Investment Bank, ING Bank, Natixis, and
Société Générale
Bahrain LNG Import Terminal Project Description
In order to supplement the natural gas supply from existing fields in Bahrain and meet the growing
domestic demand, Nogaholding, the business and investment arm of the National Oil and Gas
Authority (NOGA), is developing a project that will enable the import of Liquefied Natural Gas
(LNG) into Bahrain.

Bahrain LNG W.L.L, a company formed by Samsung C&T Corporation, Teekay LNG Operating
LLC, and Gulf Investment Corporation together with the Bahrain National Oil and Gas Holding
Company (Nogaholding), will construct and operate an LNG import terminal for a period of 20
years on behalf of the National Oil & Gas Authority (NOGA) of Bahrain. Bahrain LNG W.L.L. is a
limited liability company incorporated under the laws of the Kingdom of Bahrain.
Nogaholding has opted to develop an offshore LNG import terminal, which includes a Floating
Storage Unit (FSU) that can be re-deployed when not needed for the import of LNG in Bahrain.
The Project has been initially sized to send out 400 million standard cubic feet per day (mmscfd)
of natural gas with the possibility to expand to 800 mmscfd in the future.
Nogaholding, in collaboration with other government agencies, conducted site evaluations for an
offshore LNG terminal and concluded that the terminal should be built off-shore from Khalifa Bin
Salman Port (KBSP), approximately 4.3 km east from the existing breakwater at the KBSP. The
offshore components will be situated within Port authority boundaries in an area that is actively
dredged to support commercial marine vessel navigation. The terminal location was identified by
the Urban Planning Authority and included in the development plan of the industrial area of Hidd.
Project Benefits
The supply of LNG to supplement domestic natural gas production will support the expansion of
economic activities in Bahrain. This will ultimately boost economic growth of Bahrain and its ability
to support population growth.
The construction and operations of Bahrain LNG (BLNG) is anticipated to generate direct and
indirect employment opportunities at local, regional and national levels.
Construction
Construction is scheduled to commence in late 2016 and complete in early 2019. The following
onshore activities are anticipated during the construction phase:
An onshore construction site and laydown area will be established to act as the main logistics hub
supporting both onshore and offshore construction works. This will require an area of approximately 9
hectares (ha) and will house site offices and be used for the temporary storage of construction materials
(e.g., pipes, piles, etc.) and in which some prefabrication works (including welding) is likely to takeplace.
Construction and installation of onshore facilities which consist of a temporary jetty, onshore pipeline,
cables, and an Onshore Receiving Facility (ORF). The temporary jetty will be approximately 100 m x 40 m.
The onshore pipeline will be a 24-inch diameter 5.4 km long high pressure natural gas pipeline
underground from the ORF to a tie-in at the BAPCO gas grid at the Hidd metering station.
Construction of wastewater infrastructure to collect and contain all wastewater. Tanks will be emptied
regularly by a contractor.
Solid wastes generated during construction such as cement and concrete waste, metal scrap, wood scrap,
cardboards and tires will be reused, recycled and disposed of accordingly.
The maximum manpower for the construction phase of the project is anticipated to peak in 2018 with
around 1,000 to 1,100 total staff and construction workers onsite. Construction labour (anticipated to be
largely expatriate workers) will be provided accommodation at existing permanent facilities.
The following offshore activities are anticipated during the construction phase:
• Dredging of the offshore terminal area and pipeline trench. Dredged material will be temporarily
stored and reused to refill the pipeline trench, or disposed of appropriately onshore.

• Construction activities will include pile driving, as well as construction and installation of the jetty,
regasification platform, and offshore terminal topsides equipment. Offshore facilities will be
constructed on piled structures topped with precast concrete platforms.
• Construction material will be supplied by transport barges.
• Construction activities for the subsea pipeline will include trenching and installation of an
approximately 6.8 km long, 24 inch diameter steel subsea pipeline. Two electrical cables will be
installed to supply power to the jetty.
• An approximately 600 m long breakwater will be constructed with rock material and Accropodes.
Breakwater construction material will be delivered using marine barges.
Operations
The operations phase is scheduled to begin in early 2019. The terminal and subsea pipeline will
have a design life of 40 years. At an operating capacity of 400 mmscfd, roughly 30 LNG cargo
deliveries are anticipated annually.
LNG will be delivered by LNG Carriers and transferred over the jetty to the FSU. The LNG will be
temporarily stored before being sent to the regasification platform adjacent to the jetty where it will
be regasified in a series of Open Rack Vaporizers (ORVs).
The regasified LNG will be sent at high pressure and temperature through a subsea pipeline to the
Onshore Receiving Facility. After treatment by nitrogen injection to meet the natural gas
specifications of Bahrain, the natural gas will be returned to a subsea pipeline through the inner
port area to a point near the Bahrain Steel property.
The natural gas will then be transferred via a buried onshore pipeline to the tie-in point with the
BAPCO grid at the Hidd Metering Station. A general schematic of the project is shown below
For the operations phase, the offshore jetty and ORF are designed to be manned on a 24 hour
basis.
Simplified Flow Diagram

Offshore Facilities
An overview of offshore facilities is shown
Offshore facilities include:
• A dual berth jetty capable of receiving LNG carriers with a capacity between 135,000m3 and
266,000m3. The jetty will provide moorings for both the FSU and an LNG Carrier. Cryogenic marine
loading arms mounted on the jetty will transfer LNG between the LNG Carrier and the FSU.
• A Floating Storage Unit will be permanently berthed at the offshore jetty to receive and provide
storage for cargoes of LNG offloaded from LNG Carriers. Pumps on the FSU will send LNG to the
regasification platform for vaporization prior to export to shore via the subsea pipeline. A Boil Off
Gas (BOG) system will collect and manage natural gas vapours generated within the FSU and
offshore terminal to prevent or any loss to the atmosphere.
• A pipe trestle linking the jetty and the regasification platform will support cryogenic pipelines for
sending LNG between the regasification platform and the jetty.
• A regasification platform will use seawater as a heat source to warm the LNG and convert it from a
liquid to a gas. Seawater flows around the outside surface of Open Rack Vaporizers (ORVs) and
vaporizes the LNG inside the ORV.
• A flare will be secured to the regasification platform to safely burn off any natural gas that must be
vented from the offshore terminal in an emergency.

• A 600m long (at the base) breakwater will provide protection from waves and current and provide a
safe mooring environment for both the FSU and LNG Carriers.
• A subsea 24-inch diameter high pressure pipeline for delivering natural gas from the regasification
platform to the Onshore Receiving Facility. Electrical and integrated fiber optic cables will be buried
beside the subsea pipeline to provide electrical power to the offshore terminal and provide
communication between the jetty and ORF. The pipeline will have a leak detection system and will
be continuously monitored for leaks. The total length of the subsea natural gas pipeline from the
regasification platform to the landfall point near the Bahrain Steel property is approximately 6.8km.
Onshore Facilities
Onshore facilities include:
• An Onshore Reception Facility (ORF) will include the main terminal control room, administrative
offices, a nitrogen production and storage plant, electrical substation, spare parts store and
workshop, and a car park.
• A water line, power cable, and a transformer step-down will be provided by the Bahrain Electricity
and Water Authority (EWA) to supply power and water to the ORF.
• A 30-meter-high vent tower at the ORF will safely vent natural gas from the ORF in the event of an
emergency.
• An onshore buried pipeline to deliver natural gas to the BAPCO (Bahrain Petroleum Company) gas
grid. The onshore route commences near the Bahrain Steel property and travels northwest to a
point near the Bahrain Praxair facility and then west / southwest along a corridor wherein BAPCO is
laying an existing pipeline to a tie-in at the Hidd Metering Station.

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Your partner in Energy Services
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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
NewBase January 2017 K. Al Awadi

New base 991 special 24 january 2017 energy news

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