New base 534 special 05 february 2015

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NewBase 05 February 2015 - Issue No. 534 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Abu Dhabi Nasr oilfield sets end-of-the-year
target after starting production
The National + NewBase
Abu Dhabi’s Nasr Field, located offshore about 130 kilometres north-west of Abu Dhabi city,
began producing oil on January 24, its operator said yesterday.
The field star ted producing at a rate of 6,000 barrels per day and is targeting 22,000 bpd
production by the end of this year in its first phase of development, with the second phase bringing
production up to 65,000 bpd by the end of 2018, according to Abu Dhabi Marine Operating
Company.

The Nasr field is part of Adma-Opco’s programme to add an extra 300,000 bpd capacity to Abu
Dhabi’s overall production levels, which
itself is part of the emirate’s broader
strategy to raise production capacity from a
current level of about 3 million bpd to 3.5
million bpd by 2017-18. Last October,
Adma-Opco said the first oil began flowing
from Umm Lulu, another of the major
offshore field developments. It began
flowing at a rate of 5,000 bpd and is
expected to reach 22,000 bpd by the end of
this year and its full field development rate
of 105,000 bpd by 2018.
In November, Adma-Opco signed three
major contracts worth US$3 billion for the
second phase of Nasr’s development, with Abu Dhabi’s National Petroleum Construction
Company, Hyundai Heavy Industries of South Korea and France’s Technip of France.
The Adma concession covers four shallow water offshore oilfields: Lower Zakum, Umm Shaif,
Umm Lulu and Nasr. Adma-Opco is 60 per cent owned by Abu Dhabi National Oil Company, with
BP holding 14.67 per cent, Total 13.33 per cent and Japan Oil Development Company 12 per
cent.

Gasco awards Spain’s Tecnicas $700m gas contract
The National + NewBase
Abu Dhabi Gas Industries, known as Gasco, said yesterday that it had awarded
a US$700 million contract to Spain’s Tecnicas Reunidas for a major
natural gas expansion project aimed at alleviating the emirate’s gas shortage.
The contract is for “package 3” of the huge Integrated Gas Development (IGD)
expansion project, which aims to yield 400 million cubic feet of gas from Abu
Dhabi National Oil Company’s offshore oilfields by 2017.
The extra supply is badly needed to meet domestic demand, which has been
growing at a rate of 15 per cent a year and has required the country to import gas in recent years.
Gasco said the new contract is the fourth to be awarded to the Spanish firm in Abu Dhabi.
“TR has successfully completed a project for the petrochemical complex of Borouge, the Sahil and
Shah Field Development project, and it is just starting up the Shah Gas Gathering Centre,” Gasco
said in a statement.
The project consists of several gas processing units, gas pipelines, condensate pipelines and all
required interconnections.
It is part of the broader IGD project, led by the Abu Dhabi national energy companies Gasco,
Adgas, and Adnoc.
Gasco completed the initial US$11 billion IGD project in 2013, facilitating the transfer of 1 billion
cubic feet a day (cfd) of high-pressure gas from the offshore Umm Shaif field via Das Island to
onshore processing facilities at Habshan and Ruwais. Shell, Total, and Partex also are partners in
the IGD.
The $10bn Shah project, another of the emirate’s projects to add new gas, began producing gas
at the end of last year. Adnoc and partner Occidental Petroleum are bringing Shah’s difficult-to-
process “sour” (heavy in hydrogen sulphide) gas to market. Adnoc and Shell are also developing
the Bab field’s sour gas.

Saudia: Yasref Refinery To Load First Gasoline Cargoes
By Reuters + NewBase
The Yasref refinery in Saudi Arabia, a joint venture between Saudi Aramco and China’s
Sinopec, will load its first gasoline cargoes later this week, according to traders and shipping
fixtures.
On Feb. 6, the 400,000 barrels per day (bpd) refinery, which has already shipped its first
diesel cargoes, will load a 60,000 tonne cargo of gasoline on the Serengeti, a panamax
tanker booked by Total’s shipping arm.The cargo will go to Fujairah, rather than Asia, as
some traders originally expected.
Total has also nominated the panamax Constantinos for another 60,000 tonne gasoline cargo
to load at Yanbu on Feb. 10. This is also likely to stay within the Middle East, according to the
fixture’s destination. “I think they want to keep some of the barrels within Saudi so will move it
from Yanbu to other ports such as Ras Tanura. It’s a long way to go and it’s easier than
trucking it,” one trader said.
European-based traders and refiners are anxiously monitoring exports from the Yasref
refinery as the new capacity will erode their market share. Mediterranean refiners in particular
are thought likely to be vulnerable to a ramp up in exports from the Middle East. “It would
eventually put pressure on the Med as we export from Europe to the Red Sea,” a trader said.
The refinery is expected to reach full capacity in mid-February.

Mauritania: Chevron buys stake off Mauritania
Chevron
Chevron’s subsidiary Chevron Mauritania Exploration Limited has reached an agreement to
acquire a 30 percent non-operated working interest in Blocks C8, C12 and C13 offshore
Mauritania from Kosmos Energy.
According to Chevron, the transaction is subject to the approval of Mauritania’s government.
Blocks C8, C12 and C13 cover a contiguous area of approximately 6.6 million gross acres in
water depths ranging between 5,249 feet (1,600 meters) and 9,842 feet (3,000 meters).
Under the agreement, Kosmos Energy retains a 60 percent interest and remains the operator.
Société Mauritanienne des Hydrocarbures et de Patrimoine Minier (SMHPM), Mauritania’s
national oil company, will continue to have a 10 percent interest.
Following any commercial discovery after the exploration phase, Chevron will become the
operator maintaining a 30 percent working interest.
Andrew G. Inglis, Kosmos Energy chairman and chief executive officer, said: “This agreement with
Chevron validates the quality and scale of our Mauritania licenses, which enabled us to
successfully farm out the acreage despite the current environment. The terms are consistent with
our business strategy of retaining operatorship through exploration and collaborating with industry
leading partners who bring significant technical expertise and strong financial capabilities.”

Kenya:Taipan Resources,update on Badada-1 well in Block 2B
Source: Taipan Resources
Taipan Resources, through its Kenya-based subsidiary Lion Petroleum,has provided an update
on drilling operations for the Badada-1 well, Block-2B, onshore Kenya.
The Badada-1 well commenced drilling operations at 14:00 GMT on 7 January 2015 and has
been drilled to a total depth of 1,647 metres MDBRT (Measured Depth Below the Rotary Table).
A 13 3/8- inch casing has been successfully run to 1,644 metres MDBRT and cemented in the 17
1/2-inch hole and the well is currently preparing to drill ahead with the 12 1/4 -inch hole section to
the next casing point which is expected to be at TD.
The well is planned to be drilled to a total depth of between 3,000 and 4,000 metres in order to
test primary targets in Tertiary age reservoirs. The well is expected to take up to 70 days from
spud to completion. The Company will provide further operational updates as the Badada-1 well
progresses. A comprehensive update will also be provided once operations on the Badada-1 well
have been fully completed and analysed.
Taipan estimates gross mean un-risked recoverable resources of 251 mmboe (Source: Sproule
International Limited (1), February 2014) for Badada. (1) Sproule completed an updated
independent assessment of the company's prospective resources on block 2B with an effective
date of Dec. 31, 2013. The independent assessment was carried out in accordance with the
standards established by the Canadian Securities Administrators in National Instrument 51-101 --
Standards of Disclosure for Oil and Gas Activities. Taipan operates and holds a 30% working
interest in Block 2B (1.35 million acres / 5,464 km2) and a 20% working interest in Block 1 (5.497
million acres / 22,246 km2) which is operated by East Africa Exploration (Kenya) Ltd, a
subsidiary of Afren plc.

China's Chongqing Plans to Have Shale Gas Production
Capacity of 30 Bcm by 2020
NaturalGasasia + NewBase
China's Chongqing municipal government last week announced plans to build shale gas
production capacity of 30 billion cubic meters (bcm) by 2020 with an annual output of 20 bcm.
According to the plan, the city will implement strategies for vertical integration in the shale gas
industry. It intends to invest in exploration and development, equipment manufacturing and cluster
development to create shale gas development zone.
Chongqing has been at the forefront of China’s shale gas industry. In July last year, Sinopec’s
Fuling field in Chongqing was verified by Chinese government as country’s largest shale gas
play. China’s Ministry of Land and Resources verified proven reserves of nearly 107 billion cubic
metres (bcm) in the Fuling shale gas field.
In October, Sinopec said that cumulative output from its Fuling shale gas project crossed 1 bcm.
The government expects country’s shale gas output to hit 6.5 bcm this year.

Oil Price Drop Special Coverage
CEO of Total sees oil price at $60/b this year
Reuters + NewBase
Oil prices are likely to remain relatively low until the summer, the chief executive of Total was
quoted as saying on Wednesday, leading the French oil major to assume an average price of $60
a barrel this year.
Talking to the privately Saudi-owned Al-Hayat newspaper on the
crude oil price outlook, Patrick Pouyanne said: "I see it as relatively
low until summer, but it is hard to predict after that. When we see the
history of the crude cycles, we notice that prices fall hard and quick
then rise back usually within 18 months.
"Because we are cautious we have adopted a price of $60 a barrel
for this year and this is more of a prediction," he was quoted saying.
Pouyanne said that despite the fall in oil prices the company would
still maintain investments in its big projects. Total has said it plans to
reduce capital spending by 10 percent this year.
"We are looking to adapt with the current prices and we have said
that we would reduce our investments program by 10 percent, but
despite that we will invest this year between $23 and $24 billion," he
told the daily.
"The adaptation happened in the US shale gas projects where we mainly drill. We can stop for a
year if we wanted and redrill later. But it is not feasible with the current prices for oil and gas." On
Total's losses from the fall in oil prices, Al-Hayat quoted him as saying: "We lose $2 billion for
every $10 drop."
Brent was 17 cents lower at $57.74 a barrel by 0742 GMT, after gaining almost 6 per cent on
Tuesday and off a near six-year low of $45.19 reached in mid-January. Oil prices may stay
depressed until the summer due to weak seasonal demand, even as the strategy of curbing the
output growth of rival producers might have started achieving results, OPEC delegates told
Reuters this week.
Does oil's rally put rebalancing at risk? Kemp
Reuters + NewBase
Brent crude prices rose almost 18 percent between Friday and Tuesday, despite the absence of
real news, which should convince even the most ardent believers in market efficiency that oil
trading is noisy and inefficient at processing new information. The 8 percent surge late on Friday
was only the third time in five years prices have jumped by three standard deviations in a single
day. The March 2015 Brent futures contract gained substantially more on Monday and Tuesday. ()

The oil research team at Morgan Stanley has written that the three-day rally is putting at risk a
more sustainable recovery later in the year. "U.S. production needs to slow sharply to balance the
(global) market, which requires low prices," they wrote in a thoughtful note published on Tuesday
("Crude oil: putting recovery at risk").
"For a more meaningful recovery, demand needs to exceed supply to work off any inventory
overhang that develops," they concluded. Premature price increases simply hamper the
rebalancing.
REAL NEWS AND NOISE
The beginning of the rally coincided with the release of data from Baker Hughes showing an
unexpectedly large fall in the number of rigs drilling for oil in the United States last week. The
decline, although larger than anticipated, was not really news. The number of active rigs had been
falling steadily for the previous seven weeks, so the trend was well understood.
The size of the move was wholly unrelated to the significance of the information that triggered it.
Instead, the rig news sparked a classic short-covering rally, as hedge funds with significant
positions betting on a further price fall found themselves losing money as oil rose, and rushed to
reduce their exposure, pushing prices up even more.
"Is the falling U.S. oil rig count really driving an oil price turnaround" analysts at Citigroup
wondered in a research note of the same title published on Wednesday. Productivity gains and
more careful selection of drilling targets will reduce the impact of rig cuts, they predicted.
But markets are not precision weighing machines. They are voting machines - subject to whims,
crazes and manias in the short and medium term as even the greatest fundamental analysts of all
admitted in their landmark work ("Security Analysis", 1934, Benjamin Graham and David Dodd).
Fundamentals always reassert themselves eventually, but it can be a long time coming, as
generations of fundamentally driven investors have discovered. Crude had become heavily

oversold in the expectation prices would continue the steady downtrend of the previous 17 weeks.
Once that assumption was invalidated, market participants and prices reacted sharply.
There is no mystery about why oil fell so far and so fast between June 2014 and late January
2015, or why the decline terminated so abruptly. Price formation in bubbles and crashes has been
thoroughly examined by Didier Sornette at the Swiss Federal Institute of Technology ("Why stock
markets crash: critical events in complex financial systems", 2003).
There is much more disagreement about where prices will settle for the rest of the year. For oil
market bears, futures must remain below $50 a barrel and perhaps even $40, to force a much
larger and sustained drop in U.S. drilling.
RIGS VERSUS PRODUCTION
Citigroup notes the largest activity declines so far have been among smaller, older, less
sophisticated rigs that drill vertical or slanted wells, rather than the most modern and powerful rigs
with horizontal capability.
In the Big Three shale formations (Bakken, Eagle Ford and Permian), which account for almost all
of the increase in U.S. oil production since 2010, 199 rigs have been idled since early October.
About 170 other rigs have been idled in conventional oilfields or more marginal plays that have
added relatively little to production growth in recent years.
By employing the remaining, larger and more modern rigs on the best and surest drilling
prospects, and withdrawing from more marginal and speculative well sites, production could be
maintained or even continue to grow, according to Citi.
The bears are almost certainly correct. The decline in production from new wells is likely to be
much smaller than the drop in the rig count owing to efficiency improvements and more selective
drilling.

Based on an analysis of drilling productivity in the Big Three shale basins, Citi estimates U.S.
production could still grow by another 700,000 to 900,000 barrels per day despite a 40 percent
reduction in rigs.
Nonetheless, in my view, the decline in the rig count is too large not to have a substantial impact.
The number of rigs active in North Dakota, for example, has fallen from more than 190 in
September and October 2014 to just 142 on Wednesday, says the Department of Mineral
Resources (DMR), which regulates drilling in the state.
In a presentation to state budget-setters last month, the DMR estimated a fleet of 140 active rigs
would be needed just to sustain output at the current level of 1.2 million barrels per day, given
decline rates on old wells.
The number of active rigs has now been reduced to this threshold level. If the DMR is correct,
output should flatten over the next few months.
PRICES RISK ADJUSTMENT
But even after the rally, the price U.S. shale oil producers receive at the wellhead remains below
breakeven levels in all but the most attractive parts of the Big Three shale plays. For example,
wellhead prices in North Dakota are only around $45 per barrel, based on an average of WTI
futures prices ($53) and posted prices ($37).
With wellhead prices at $45, the DMR projects that state production will decline by around
100,000 barrels per day by the start of July. State oil producers need wellhead prices of around
$55 per barrel to sustain output, which implies WTI prices of perhaps $60 or more.
The recent rally in Brent and WTI futures is unlikely yet to put the rebalancing at risk. Output is still
likely to fall in the second half of the year.
Underscoring the depth of the adjustment already under way, National Oilwell Varco , the largest
supplier of drilling equipment in the United States, reported that fourth-quarter orders in its rig
technology equipment division were down 90 percent compared with a year earlier.
"Customers are delaying purchases of both capital and consumables wherever possible, seeking
to conserve cash in the face of market uncertainty," the company's chief executive said on a post-
earnings call. As long as wellhead prices remain below breakeven levels, drilling will continue to
slow, and output will remain on course to peak around the middle of the year and then start to
decline.

LNG Supply Seen Falling After 2020 as Oil Plunge Delays Projects
(Bloomberg)
Global output of liquefied natural gas may shrink after 2020 as falling oil prices prompt producers
to withdraw plans for new plants and delay investments.
Projects that sell LNG linked to the price of oil will be under pressure with crude between $50 and
$60 a barrel, and more than $60 billion in cash flow may be affected this year, Wood Mackenzie
Ltd. said in an e-mail on Feb. 4. Projects with more than $100 billion of investment are at risk of
delays or cancellation, according to the Edinburgh-based consultant.
Companies have moved to cut costs after benchmark crude slumped almost 50 percent last year
as the U.S. pumped oil at the fastest rate in more than three decades, exacerbating a global glut.
Royal Dutch Shell Plc, BG Group Plc, Petroliam Nasional Bhd and Chevron Corp. have cut or
delayed spending on LNG projects from Australia to Canada.
“We’ll see a marginal tightening in the market,” said Leigh Bolton, managing director of Holmwood
Consulting, a Surrey, England-based energy consultant. “Some of the projects will disappear
entirely while some of them will be deferred for three to five years.”
Brent crude added 74 cents to $54.90 a barrel on the London-based ICE Futures Europe
exchange at 9:53 a.m. Singapore time. Oil may fall below a six-month forecast of $39 a barrel and
rallies could be thwarted by the speed at which lost shale output can recover, Goldman Sachs
Group Inc. said last month.
Long-term LNG contracts can be priced off by up to 15 percent of oil prices, according to a Jan. 5
report by Bloomberg New Energy Finance. Spot LNG prices fell to their lowest since June 2010 at
$7 per million British thermal units on Feb. 4, according to data from New York-based Energy
Intelligence’s World Gas Intelligence publication.
Sunk Costs
“From 2018 to 2022, the market is very well supplied as there are new U.S. and Australian
projects ramping up,” Nicholas Browne, Wood Mackenzie’s senior manager for primary fuel
research said in a phone interview last month. “Producers will be affected because costs are sunk
into projects whereas the returns they get are significantly less as the lower oil price works its way
into contracts,” said Browne.
Costs in Asia, the region that buys the most supercooled fuel, will this year average below $10 for
the first time in four years as new projects in Australia and the U.S. boost supply through 2016,
Bloomberg New Energy Finance said.
“Low oil price is good for the LNG business because it drives out the unsuccessful projects,” said
Bolton.

NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Your partner in Energy Services
NewBase energy news is produced daily (Sunday to Thursday) and
sponsored by Hawk Energy Service – Dubai, UAE.
For additional free subscription emails please contact Hawk Energy
Khaled Malallah Al Awadi,
Energy Consultant
MS & BS Mechanical Engineering (HON), USA
Emarat member since 1990
ASME member since 1995
Hawk Energy member 2010
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 01 February 2015 K. Al Awadi

New base 534 special 05 february 2015

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