New base 781 special 07 februaury 2016

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NewBase 07 February 2016 - Issue No. 781 Edited & Produced by: Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Yemen: Petsec Energy acquires operatorship of the Damis
(Block S-1) Production Licence in Yemen
ource: Petsec Energy
Australia’s Petsec Energy has advised a further significant expansion of its oil and gas interests
in the Republic of Yemen with the acquisition of entities holding the entire (100%) participating
interest (82.5% equity interest) and operatorship of the Damis (Block S-1) Production Licence.
The Damis (Block S-1) Production Licence holds five sizeable oil and gas discoveries – the
developed and producing, until suspended in 2014, An Nagyah oil field, and a further four
undeveloped oil and gas fields within the licence area – Osaylan, An Naeem, Wadi
Bayhan and Hamel.
The An Nagyah oil field commenced production in March 2004 and has produced 25 million
barrels of oil to-date from 25 wells, reaching a peak oil rate of 12,716 BOPD in March 2006. The
field was producing at a limited rate of 5,000 BOPD at an estimated lifting cost of US$7.50/barrel,
when it was shut in at the end of February 2014. Production at the shut-in rate is expected to
extend beyond 2023, the initial term of the Production Licence.
Canadian reserve engineers DeGolyer and MacNaughton Canada, the reserve auditor to
TransGlobe Energy Corp for the Damis Block S-1, which reports have been released to the
Toronto Stock Exchange, has been commissioned by Petsec Energy to undertake an economic

reserve audit to assess the remaining economic benefit to the Company. These results will be
released in due course. The newly acquired Damis (Block S-1) Production Licence, which
continues Petsec’s stated policy of acquiring developed and undeveloped oil reserves in the
Middle East region, is located approx. 80 kms to the southwest of the Company’s exploration
Block 7 which holds the Al Meashar oil field discovery, in the Sab’atayn Basin, in central West
Yemen.
Petsec’s purchase of the
Damis (S-1) Production
Licence was achieved
through the acquisition by
the Company’s wholly
owned subsidiary Petsec
Energy (Middle Eastern)
Limited, of all the shares of
Yemen (Block S-1) Inc., a
wholly owned subsidiary of
Occidental Petroleum
Corporation, and the
operator of Damis (Block S-
1) holding a 75%
participating interest, and
the acquisition of all of the
shares of TG West Yemen
Inc., a wholly owned
subsidiary of TransGlobe Energy Corp, which holds a 25% participating interest.
The acquisition consideration is comprised of a base cash payment of US$0.7 million plus trailing
payments, subject to the recommencement of production and other conditions precedent. The
block is currently subject to Force Majeure due to the current political issues in Yemen and
consequent inability to ship oil from the West coast of Yemen, at the export pipeline terminus for
the An Nagyah oil field.
Mr. Maki Petkovski, Chief Executive Officer of Petsec Energy (Middle Eastern) Limited, said 'the
Damis (Block S-1) Production Licence acquisition materially increases the Company’s developed
oil and gas reserves and provides further major development opportunities which, when
developed, would substantially increase the block’s oil and gas production.
The block contains significant existing infrastructure, including surface facilities with a capacity to
process up to 20,000 barrels of oil per day (BOPD) and an 80,000 BOPD pipeline which joins the
200,000 BOPD Marib export pipeline to the Ras Isa terminal on the Red Sea coast, to the West.
The Marib pipeline was the export pipeline for Damis Block S-1 crude sales until production was
suspended in 2014. Excess capacity exists in the Marib export pipeline for restart of the An
Nagyah oil field and for future development of the remaining undeveloped oil fields in the Damis
(Block S-1) block.'
'It is Petsec’s intention to restart production as early as is feasible, either by piping or trucking or
a combination of both, even while conflict exists elsewhere in the country.'

Morocco: marks progress on 500MW solar park
The National - LeAnne Graves
Morocco held a three-in-one ceremony on Thursday for the first two phases of what will be one of
the world’s largest solar parks at over 500 megawatts of capacity. A ceremony was held in
Ouarzazate to officially inaugurate Noor 1 and break ground on the second phase, which includes
the Noor 2 and 3 projects.
The Noor 1 phase, totalling 160MW of capacity, was scheduled to be officially launched before the
end of last year, but the ceremony was postponed by Moroccan officials. Paddy Padmanathan,
chief executive of Saudi Arabia’s Acwa Power and the lead developer of the project, said that only
the ceremony had been delayed, but that the plant had come online as scheduled in 2015.
Acwa and its technical partner Sener of Spain signed the public private partnership agreement
with the Moroccan Agency for Solar Energy (Masen) for Noor 1 in 2013. The Saudi firm has gone
on to successfully bid for the Noor 2 and 3 phase, totalling 200MW and 150MW, respectively, with
a total investment of about US$3 billion.
“We’re very comfortable in Morocco as an investment destination,” Mr Padmanathan said. “We will
continue to investment more.” Morocco, unlike its North African neighbours, has few hydrocarbon
assets such as oil and gas and has a high import bill because it is forced to tap sources abroad to
meet more than 90 per cent of its energy needs.
Therefore, the country has set out an ambitious target to have renewable energy make up 42 per
cent of its power generation mix by 2020, which will then increase to 50 per cent by 2030.
And Morocco is poised to do just that, particularly as it showcases some of the lowest solar pricing
yet for concentrated solar power (CSP) technology, which typically costs more compared with
photovoltaic applications because it has storage capabilities.
According to the Abu Dhabi-based International Renewable Energy Agency (Irena), the average
cost of electricity generated from CSP ranges between 22 US cents and 25 cents per kilowatt
hour.
Yet, as is typically the case when Acwa bids for a project, such as in Dubai last year, in Morocco
the company came in with rates that beat the average price by about 30 per cent. For Noor 2, the
bid came in at 15.67 US cents per kilowatt hour while offering a tariff for the Noor 3 of 16.31 cents.
Morocco’s energy minister, Abdelkader Amara, said at the Paris climate summit in December that
the Ouarzazate solar programme has already given the country significant savings on energy
costs in its first year.

Kenya: Africa Oil completes Kenyan farmout deal with Maersk Oil
Source: Africa Oil
Africa Oil Corp has completed the previously announced (November 9, 2015)
farmout with Maersk Oil & Gas related to Kenyan Blocks 10BB, 13T and 10BA.
At completion, Africa Oil received US$427 million from Maersk. This amount represents US$344
million of reimbursed past costs incurred by Africa Oil prior to the agreed March 31, 2015
effective date of the farmout and US$83 million representing Maersk’s share of costs incurred
between the effective date and December 31, 2015, including a carry reimbursement of
US$15MM of exploration expenditures.

An additional US$75 million development carry may be available to Africa Oil upon confirmation
of existing resources, which is expected to take place in the first quarter of 2016. Upon Final
Investment Decision ('FID'), Maersk will be obligated to carry Africa Oil for an additional amount
of up to US$405 million depending on meeting certain thresholds of resource growth and timing
of first oil.
The resulting interests in each of Africa Oil’s Kenyan blocks are as follows:
The farmout of 50% of Africa Oil’s interest in the Rift Basin and South Omo Blocks remains
subject to Ethiopian government approval, which is expected in the near term. At completion of
the Ethiopian portion of the Maersk farmout the respective working interests in each of Africa
Oil’s Ethiopian blocks will be as follows:
Keith Hill, Africa Oil's CEO, commented, 'We are very pleased to have completed the Kenyan
portion of our farmout to Maersk. We feel Maersk will be an excellent partner in terms of
technical and financial strength and experience critical to moving the development project
forward. This transaction puts Africa Oil in the enviable position of not requiring any additional
equity financing prior to first oil and will allow us to weather the current difficult oil price
environment should it continue into 2016.'

Nigeria: FPSO en route to Aje field, offshore Nigeria
Source: Panoro Energy / energy-pedia
Panoro Energy, a partner in the Aje field, offshore Nigeria, reports that final works on the floating
production, storage and offloading vessel ('FPSO') have been completed, and the vessel has
now left Singapore. The vessel is expected to arrive in Nigeria mid-March 2016, following a brief
stop in Cape Town.
All key equipment related to the field development has been delivered to Nigeria. Anchor
handling operations in the field started in January and will continue until mid-February. The
construction vessel has commenced operations and will install the subsea equipment including
the manifold and flowlines during February. Once the FPSO arrives in Nigeria it will be hooked-
up to the mooring system and risers and a short test of the production systems will be conducted.
Panoro’s Chief Executive Officer, John Hamilton, said: 'We are excited to be approaching first oil
at Aje, offshore Nigeria. Significant operational and contractual progress has been made on the
final phase of field development. With the drilling phase now concluded, the installation work and
the arrival of the FPSO are the main remaini ng work streams. The field is expected to be
producing by the end of March 2016.'
Aje field
Panoro Energy has a 6.502% interest in OML 113 which is operated by Yinka Folawiyo
Petroleum (YFP) and is located in the extreme western part of offshore Nigeria adjacent to the
Benin border. The licence contains the Aje field as well as a number of exploration prospects.
The Aje field was discovered in 1997 in water depths ranging from 100-1,500m. Unlike the
majority of Nigerian Fields which are productive from Tertiary age sandstones, Aje has multiple
oil, gas and gas condensate reservoirs in the Turonian, Cenomanian and Albian age sandstones.
In March 2014 the Government of Nigeria approved of the Aje Field Development Plan
('FDP') and in October 2014 the Final Investment Decision ('FID') for the project was made.
The FDP describes a development of the Aje Cenomanian oil reservoir via two subsea wells, the
new Aje-5 well and a re-completed Aje-4 well, and a leased FPSO. The initial 2 wells will produce
an estimated mid case of 28.5MMbbls 41°API oil with production starting early 2016 at a rate of
circa 1,100 bbls/day (net to Panoro).

Georgia: High hopes for more gas from Eastern neighbours
The article was first published in Natural Gas Europe
Amid Georgia’s negotiations with both Russia and Eastern countries to find the ways for its
increasingly gas demands, Azerbaijan boosted gas export to this country in winter. Turkmenistan
also says it is intensifying negotiations over a trans-Caspian pipeline to supply its gas to the West,
although it will have to agree on using capacity in another country's export system.
Azerbaijan’s energy
minister told NGE on
January 29 that Azerbaijan
has the capability to
increase gas deliveries to
Georgia during this winter
to meet their demands.
He added that the ratio of
Azerbaijan’s gas deliveries
to Georgia in winter-
summer was 60:40, but he
agreed to change this ratio
to 70:30, because
Georgia’s gas demand in
winter is growing, he said.
Azerbaijan gas supply
company, affiliated to
Socar, also told NGE that
Azerbaijan delivered about
3.2mn m³ of gas (including the transit fee or 5% of the transited gas through Georgia to Turkey) to
Georgia on January 31, about 220,000 m³ more than on the previous day. He said that Baku
would supply more 50mn m³ to Georgia this winter. Last year, Georgia received 1.4bn m³ of
commercial gas as well as 721mn m³ of gas as transit fee.
Turkmenistan’ oil and gas ministry announced on February 1 that the national program on energy
export diversification envisages developing new routes towards Europe as well as the east.
Russia said last month that it has stopped buying Turkmen gas while Iran, as Turkmenistan’s
other gas customer, is intensively boosting both gas production and cross-country pipelines.
A 300-km subsea pipeline running through the Caspian Sea to Azerbaijan can connect Turkmen
gas to the Southern Gas Corridor (SGC) gas pipeline, aimed to transit Caspian gas to Europe. It

would be beneficial for Georgia as well, because the more gas there is in the SGC, the more it can
earn in transit fees. But there will be opposition to the project as the Caspian Sea littoral states
have not yet agreed on whether that is legal or not. Coming to Central Asia, Kazakhstan also
increased gas production in 2015, eying more growth in coming years.
Kazakistan added 1 bn m³ to its yearly gas output from a field in Mangistau district, in the
southwest country, with the start of it Shagyrly-Shomyshty gas field. The gas production target has
been fulfilled, chief of the Mangistau district Alik Aydarbayev said during a briefing. He added that
the total volume of gas extraction reached 2.5bn m³ in Mangistau district in 2015. Kazakhstan
inaugurated Shagyrly-Shomyshty gas field on Febuarary 10, 2015. The field's reserves are 32bn
m³.
Kazakhstan increased gas production by 5.2% in 2015, up from 45.713bn m³ in 2014, the
statistics committee of the Kazakh economy ministry reported.
On the other hand, Uzbekistan announced on January 28 that it expects to see 8% more spent
this year than last on developing and upgrading the gas industry. This year’s investment is
planned to reach $2.798bn, according to the decree of the president Islam Karimov.
According to BP’s statistical review, the country produced 3.1mn mt of oil and 57bn m³ of gas in
2014, the latest year for which BP data are available.

US: High inventories help push crude oil prices to lowest levels in 13 years
Source: U.S. Energy Information Administration, Weekly Petroleum Status Report
Several factors have played a part in pushing U.S. crude oil prices below $30 per barrel (b),
including high inventory levels of crude oil, uncertainty about global economic growth, volatility in
equity and nonenergy commodity markets, and the potential for additional crude oil supply to enter
the market. Crude oil and petroleum product inventories, both domestically and internationally,
have been growing since mid-2014 and are above five-year averages for this date.
Although there is still traditional, on-land storage space available, higher inventory levels and
expectations for global inventories to continue building in 2016 are lowering crude oil and
petroleum product prices for near-term delivery:
• Total U.S. commercial crude oil inventories as of January 29 were 503 million barrels, 132
million barrels above the 2011-15 January average. This marks the first time that U.S.
inventories exceeded 500 million barrels.
• Crude oil inventories at Cushing, Oklahoma, the delivery point for the West Texas
Intermediate (WTI) futures contract traded on the New York Mercantile Exchange (Nymex),
are 23 million barrels above the five-year average as of January 29.
• Total U.S. distillate inventories (which include heating oil and diesel fuel) are 22 million
barrels above the five-year average, and motor gasoline inventories in the United States
also recently moved above historical averages.
When inventories are high and rising, costs to store crude oil and petroleum products generally
increase. In futures markets, where people can buy commodities for specific delivery times in
future months, high storage costs often mean that long-term deliveries are priced higher than
near-term deliveries, a situation known as contango. One metric for this is the difference in

contract prices between the front month (the most proximate future month) and the contract for
one year out, known as the 13th-to-1st month spread, as shown in the graphic below.
From 2010 to 2014, when global liquid fuel oil inventories were generally declining, the front
month contract for Brent crude oil traded higher than the futures delivery one year out. Since then,
the market has changed. Through January 2016, Brent and WTI front month prices traded on
average about $8/b lower than futures price for delivery one year out.
When front month futures prices reach large discounts to contracts for delivery of crude oil months
or years in the future, market participants may store oil on ships, also known as floating storage.
By purchasing crude oil on the spot market, selling a longer-dated futures contract, and chartering
and manning a vessel, market participants can lock in their rate of return.
Because of the costs associated with chartering a ship and manning it for several months, floating
storage does not typically become economical until contango reaches $10-$12/b. Trade press and
news reports do not currently indicate widespread amounts of crude oil being purchased for
floating storage.
The shape of the futures strip, which represents the price of petroleum products for delivery at
each contract month, also drives decisions regarding storage of diesel fuel and gasoline. Ultra-low
sulfur diesel (ULSD) inventories in the United States have grown more than total motor gasoline
inventories since mid-2014.
Correspondingly, the discount of the front month gasoline contract to the futures contract for
delivery one year in the future is significantly less than the discount for ULSD. With the distillate
market in steep contango in January, small amounts of floating storage are being reported near
ports located in northwest Europe, where low water levels in rivers have slowed deliveries of
petroleum products.

NewBase 04 February 2016 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil falls in volatile trade as glut concerns face OPEC cut uncertainty
Reuters + NewBase
Oil prices ended the week lower in choppy trading on Friday, snapping two weeks of gains, as a
frenzy of speculation about a possible deal between top oil producers clashed with concerns
about a growing supply glut.
After a volatile week's trading, much is riding on Sunday's meeting between Venezuelan Oil
Minister Eulogio Del Pino and his Saudi counterpart Ali al-Naimi in Riyadh, after Del Pino's
discussions with the Qatari and Omani ministers this week.
As cash-strapped Venezuela tries to rally support for concerted action between members of the
Organization of the Petroleum Exporting Countries to boost prices, Sunday's meeting is seen
"make or break" for a possible deal, said Tim Evans, energy futures specialist at Citi Futures.
Adding to this week's rollercoaster ride in prices was the sudden liquidation of a $600 million
leveraged fund bet on falling prices.
Investors were also weighing a string of conflicting indicators on Friday as the dollar recovered
some of the ground lost over the past two days while investors continued to fret about growing
oversupply, with U.S. inventories hitting record highs last week amid concerns about a slowing
global economy.
The pickup in the market earlier this week was not really warranted, Gene McGillian, senior
analyst at Tradition Energy said, referring to the market seemingly brushing aside extremely
bearish inventory data earlier this week.
"Today when the dollar tried to push up, which I attribute mostly to a little weekend covering, you
started to see some sellers come back in the oil markets," he said.
Global benchmark Brent crude futures settled down 40 cents, or 1.2 percent at $34.06 a barrel,
after trading between $35.14 and $33.81. They last traded down 44 cents at $34.02.
U.S. West Texas Intermediate crude futures closed 83 cents, or 0.1 percent lower, at $30.89 a
barrel, after touching a high of $32.45. They last traded down 87 cents at $30.85.
Prices briefly turned positive after data showed U.S. energy firms this week deepened their oil rig
cuts in the seventh week of declines, to the lowest levels in nearly six years.
U.S. oil is now down more than 8 percent on the week after two straight weeks of gains.
Prices briefly turned positive after data showed U.S. energy firms this week deepened their oil rig
cuts in the seventh week of declines, to the lowest levels in nearly six years.
Oil price special
coverage

The number of rigs in U.S. oil fields continued to fall, dropping by 31 to a total of 467 in the
previous week, according to Baker Hughes. At this time last year, U.S. drillers had 1,140 rigs
online.
Both contracts were stuck in a narrow $1.50 range and on track for their first weekly loss in two
weeks as hopes of an OPEC-led production cut that boosted prices in January have faded and
concerns about a global supply glut have returned.
In a sign that low prices are having a limited impact on production, only around 100,000 barrels
per day of oil production has been shut in globally to date - about 0.1 percent of global output -
industry research group Wood Mackenzie said on Friday.
Morgan Stanley warned on Friday that a rebalancing in the oil market may not occur until mid-
2017.
As markets try to balance themselves, it will likely lead to further volatility as investors close
excessive positions, ABN Amro said in a note.

US oil explorers park more rigs as crude glut stalls rally
Bloomberg + NewBase
Explorers this week idled the most drilling rigs in US oilfields in almost a year as a historic high in
US crude supplies undermined efforts by the market to rally.
Rigs targeting oil in the US fell by 31 to 467, Baker Hughes Inc. said on its website Friday. It was
the biggest one- week drop for oil rigs in 11 months. Natural gas rigs were trimmed by 17 to 104,
bringing the total down by 48 to 571. Explorers and producers in the Eagle Ford of south Texas
had the biggest fallback in activity, dropping eight oil rigs and leaving 55 to work there.
Now that producers have given up hope for a recovery in the first half of the year, “it’s time to cut
hard and cut fast,” Brian Uhlmer, managing director at GMP Securities in Houston, said Friday in a
phone interview. “It’s just been a slow trickle for the last six months or so.”
US supplies rose above 500 million barrels through January 29, the highest level since 1930 in
monthly government data compiled by the Energy Information Administration. Venezuelan Oil
Minister Eulogio Del Pino is due to travel to Saudi Arabia, continuing his tour of producers in a bid
to encourage cooperation to boost prices.
Still Vulnerable
“Absent any surprise on Sunday when Del Pino meets” with Saudi Arabian Oil Minister Ali al-
Naimi “I see prices remaining vulnerable to the downside, as the oil market is still oversupplied,”
said Giovanni Staunovo, an analyst at UBS Group AG in Zurich. “We do not expect a coordinated
production cut.”
America’s oil drillers have idled about two-thirds of the country’s rigs since October 2014 as the
world’s largest crude suppliers battle for market share. Despite the cutbacks, US production has
remained stubbornly high as new techniques that increase efficiency keep the oil flowing.
US production fell by 7,000 barrels last week to 9.21 million barrels a day, according to weekly
Energy Information Administration data. It was the second time in eight weeks that US output
dropped.
While crude rallied 14 per cent in the final two weeks of last month, it’s heading toward a weekly
decline, down about 15 per cent this year amid brimming US crude stockpiles and concern about
Iran’s effort to boost exports after the removal of sanctions.

Given that there were about 200 operators running one- or two-rig drilling programs at the end of
the year, it’s easy to see that activity getting cut back, dropping the oil rig count into the 300s this
year, Matt Marietta, an analyst at Stephens Inc. said Friday in a phone interview.
“There was a belief out there in the market that there would be this refunding of capital budgets
because we got to year end,” Marietta said. “I think that’s been completely disproved.”
Four of America’s shale gas plays are now void of all drilling
Surging output has sent gas futures tumbling, forcing drillers to abandon marginal plays in favour
of more profitable areas. Drilling has ground to a halt in two gas basins in Oklahoma, along with
the Fayetteville reservoir in Arkansas and the Niobrara formation in Colorado and Wyoming, data
from Baker Hughes Inc. show.
Even as US gas rigs drop to the lowest on record, there’s still no sign of declining production — at
least, not yet. Output from shale formations has left stockpiles at a seasonal record as a mild
winter curtails demand, expanding a supply glut that’s threatening to keep prices depressed into
the second half of the year.

“The decline in rigs is really accelerating, especially in some of these marginal plays where prices
aren’t high enough to justify production,” said John Kilduff, a partner at Again Capital LLC in New
York. “Drilling is still profitable in other areas, though, so it may be a while before a recovery really
takes hold.”
Gas futures on
the New York
Mercantile
Exchange slid
10 per cent
last week to
settle at
$2.063 per
million British
thermal units
on Friday. The
March contract
dropped to
$1.954 in
intraday
trading on
Feb. 4, the
lowest since
1999 for the
time of year.

NewBase Special Coverage
News Agencies News Release February 2016
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
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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 04 February 2016 K. Al Awadi

New base 781 special 07 februaury 2016

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