NewBase 644 special 09 july 2015

Copyright © 2015 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,
or otherwise copied without the written permission of the authors. This includes internal distribution. All reasonable endeavours have been used to ensure the accuracy of the information contained in this
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NewBase 09 July 2015 - Issue No. 644 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
Oman planning to build ‘biggest’ solar energy plant in Middle East
Saudi Gazette + NewBase
Petroleum Development Oman (PDO) said on Wednesday it would build the Middle East’s largest
solar power plant in a $600 million deal with California’s GlassPoint Solar to reduce pressure on
its natural gas reserves.
“The project will be fully financed by PDO,” Raoul Restucci, managing director of the sultanate’s
top oil and gas exploration and production firm, told reporters. GlassPoint will provide technology
and help to build the plant.
Construction of the first phase of the plant, ultimately expected to generate 1,021 megawatts, will
start this year and the facility is to begin generating steam in 2017. Oman is an oil exporter but
lacks the ample reserves of its Gulf neighbors, so it is eager to get more from its oilfields by
pumping high-pressure steam into ageing wells.
At the same time, its ambitious industrial development plans promise to siphon off supplies of
natural gas that would traditionally be used to generate the steam. So it plans to use solar power
to produce steam; the new plant will save 5.6
trillion British thermal units of natural gas each
year, Restucci said.
Last September Oman’s State General Reserve
Fund, a sovereign wealth fund, and other
investors said they were injecting $53 million
into GlassPoint to accelerate the deployment of
solar steam generators. GlassPoint, which has
had a pilot steam-generating project in Oman
since late 2012, has said it aims to develop a
solar manufacturing capability and local supply
chain in the country

Philippine: Gas Deposits Discovered in the north – Isabela Province
News Agencies + Gulf News
The Department of Energy (DOE) has confirmed that Philippine National Oil Company–
Exploration Corporation (PNOC-EC), a government-owned entity, has discovered natural gas
deposits here not far from a field that used to supply fuel for the gas-fired power plant in the
province.
The find fans hopes that the country could push for more such exploration projects in its bid to
achieve energy independence. Initial results from the Mangosteen-1 well, in Cagayan Basin in
Santiago City, Isabela, show promising quantities of natural gas that can be harvested from the
well.
The state-owned corporation will
now determine the commercial
viability of the said find. The
discovery was found in an area
covered by Service Contract 737,
an onshore block located in the
southern part of the Cagayan
Basin, covers an area of 360
square kilometer, and is fully
owned and operated by state-run
PNOC-EC.
Gemiliano Lopez Jr, PNOC-EC
chairman, told the Philippine media
that the gas well, explored through
the "Mangosteen" project under SC
737, may perhaps be the next
major natural gas supply in the
country next to Malampaya field.
The official said the good news
was relayed to President Benigno
Aquino III. “We found natural gas
within the president’s term, one
that would complement the
production of the Malampaya
offshore project in Palawan and
allow us to supply additional cheap
and clean energy to our people.”
“We are extremely confident of
finding the country’s next gas field
that can provide an additional 100
megawatts of energy using clean
natural gas,” Lopez Jr. said.

Russia's Gazprom cancels Saipem deal on Black Sea gas pipeline
Source: Reuters
Russia's Gazprom has cancelled a contract with Italian oil services group Saipem to build the first line of a
gas pipeline beneath the Black Sea, the Russian state gas company said in a statement on Wednesday.
Gazprom said it will start talks with other potential contractors to build the first line of the Turkish Stream
pipeline, which would run beneath the Black Sea to Turkey. The project would consist of four lines, each
capable of carrying 15.75 billion cubic metres of gas per year.
Saipem said last month it was asked by Gazprom to start work on a pipeline under the Black Sea, which
should avoid Ukraine as a transit country for roughly half of Russian gas shipped to Europe.
On Wednesday, Gazprom said it canceled the deal with Saipem after it faced a number of issues regarding
the Turkish Stream. Gazprom did not elaborate with whom it faced issues.
The first line, which was due to be launched next year, would have supplied only Turkey. However, Russia
and Turkey have yet to agree on the price of the gas. Turkish energy company BOTAS has threatened
Gazprom with international arbitration if a price deal is not reached.
The Turkish Stream project replaced an earlier proposal from Gazprom called the South Stream gas
pipeline, which would have run from Russia to Bulgaria across the Black Sea. Saipem won contracts worth
2.4 billion euros ($2.7 billion) last year mainly to build the first line of the South Stream gas pipeline.
Gazprom abandoned the project last year due to objections from the European Union.

Rosneft signs deal to buy into Essar’s Vadinar refinery
Reuters + Gulf News+ NewBase
Russia’s top oil producer Rosneft has made a significant step in its efforts to expand its global
reach by signing a preliminary deal with Essar Group about acquiring up to 49% of the Vadinar oil
refinery in India.
Rosneft, the world’s top listed oil producer, has long sought to increase its exposure to the global
markets but its efforts have been hampered by Western sanctions over Moscow’s role in the
Ukraine crisis.
State-controlled Rosneft said yesterday that it has also finalised a deal to supply 10mn tonnes of
oil a year (200,000 barrels per day) to the refinery over 10 years. “Thanks to this agreement
Rosneft grants itself a secure market outlet of crude oil, which will create an additional possibility
of production planning and marketing,” the company said in a statement.
The deal to buy a stake in the refinery had been delayed due to difference over the price, sources
told Reuters last month. It was unclear whether a price has now been agreed. Sources said last
month that Rosneft would pay less than $2bn for the stake and that Essar wanted a higher price.
Rosneft said the deal is still subject to corporate approval.
Mumbai-based Essar, whose
business interests include steel,
oil and gas, power and ports,
has been forced to consider
selling some of its assets to
reduce its debt pile, after
expanding in India and
overseas in the last few years.
Essar’s founders own 90.5% of Essar Oil, of which 65.6% is in the form of overseas depository
shares. Essar depends heavily on Iran to feed its 400,000 bpd Vadinar refinery. Rosneft said
yesterday that the partners intended to increase the refinery’s capacity to 45mn tonnes (900,000
barrels per day) by 2020.
The oil supply agreement was preliminary signed in December during Russian President Vladimir
Putin’s visit to India. Processing of 200,000 bpd of Russian oil will hurt the profitability of Essar’s
Vadinar refinery because of the higher transport costs and yield.
Rosneft’s Chief Executive Officer, Igor Sechin, did not rule out yesterday that the company may
supply oil via swaps, but declined to elaborate. A source said last month that Rosneft may supply
Venezuelan oil to the Essar refinery or it may sell Iranian oil to Essar, once international sanctions
against Tehran are lifted.

France: In shale-wary France, an attempt to revive former coal region with gas
Source: Reuters
France could get the equivalent of 10 years of gas consumption by exploiting the methane trapped
in the former coal mines of its deprived eastern regions, a French company running a rare
domestic exploration programme said on Wednesday. France, which slammed the door on
developing shale gas due to environmental concerns and blocked many exploration permits, has
discretely supported efforts by Française de l'Energie, based in the Lorraine region, to exploit so-
called coalbed methane.
'France is completely dependent on imports, so it's rather interested in seeing we can produce a
gas which is clean and near existing infrastructure,' said Julien Moulin, head of the company
formerly known as European Gas. 'The political climate is not the most favourable to issue
hydrocarbon permits but the administration has understood very well that our project is very
different from other players looking for shale gas,' Moulin told Reuters in an interview.
Known to wary coal miners as 'firedamp', coalbed methane is the flammable gas that would
become trapped in pockets between the coal and often triggered lethal underground explosions.
Moulin said the region is well placed to become a profitable gas hub because it sits where
pipelines bringing Russian gas arrive on French territory and therefore does not need major
infrastructure work. Also, most of the geology of the Lorraine basin was mapped during its 19th
and 20th century heyday as France's coal mining heart, and later in the 1980s when companies
such as ConocoPhillips attempted exploratory drilling, he said.
Moulin said with the help of new horizontal drilling techniques he can extract gas more
competitively than those failed attempts, with a breakeven point below $5 per thousand cubic feet,
compared to $7-$8 on the spot market.
Française de l'Energie, which has invested 40 million euros ($44 million) since 2009, expects to
be able to market the gas in 2017 and is in talks with large industrial consumers in the region such
as Total and Solvay. The company is backed by wealthy industrialists such as the Rothschilds, the
Lorenceau family which founded Addax Petroleum and sold it to Sinopec, and the Michaud family,
which has backed Maurel & Prom. Moulin does not rule out an IPO in the future.

USA: Net petroleum product exports continue to increase
Source: U.S. Energy Information Administration, Petroleum Supply Monthly
Over the past decade, domestic refinery output of petroleum products has grown significantly
while consumption has declined, resulting in a major increase in product exports. Petroleum
product exports averaged 4.1 million barrels per day (b/d) in the first four months of the year, an
increase of 0.5 million b/d over exports the same time last year. Product imports are also higher
than last year, but to a lesser extent, leading to an increase in net petroleum product exports.
Import and export patterns vary by region, with most exports leaving from the Gulf Coast
(Petroleum Administration for Defense District 3), and imports coming to the East Coast (PADD
1). Record-high refinery runs and increased global demand for petroleum products from the
United States continue to push exports higher.
More than half of the country's refinery capacity is located in PADD 3, and roughly 75% of U.S.
product exports are sent from that region. Through April, Gulf Coast petroleum product exports
were up 444,000 b/d compared with the same time last year. Gasoline, distillate, and jet fuel
exports combined accounted for 40% of the increase.
Higher levels of gasoline and distillate exports were sent to countries in the Western Hemisphere,
while gasoline exports to Africa decreased slightly. Jet fuel exports have primarily increased to
Western Europe, Central America (plus Mexico), and South America, and to a lesser extent Africa.
Propane and naphtha exports are each more than 150,000 b/d higher than last year, and are
primarily sent to Asia.
Product imports remain an important source of supply on the East Coast, supplementing in-region
refinery production and receipts from the Gulf Coast and, to a lesser extent, from the Midwest

(PADD 2). U.S. motor gasoline product supplied has been 71,000 b/d higher so far in 2015
compared with last year, and imports of total motor gasoline (including both blending components
and finished gasoline) have increased by 103,000 b/d.
Petroleum product markets on the West Coast are typically tightly balanced, with in-region refinery
production nearly evenly matched with demand. The West Coast is largely isolated from the rest
of the country's petroleum markets because there are no pipelines that cross the Rocky
Mountains. However, in recent years, the region's supply of distillate fuel has exceeded demand
and, as a result, exports have increased.
West Coast distillate exports averaged 117,000 b/d so far this year, in line with the previous two
years and 37,000 b/d higher than in 2012. During times of supply disruptions, imports to the West
Coast often increase to replace lost supply from in-region refineries, as has been the case so far
in 2015. Following an outage caused by an explosion and fire at ExxonMobil's Torrance,
California, refinery in mid-February, gasoline imports to the West Coast increased, and they have
averaged 37,000 b/d so far this year, more than double compared with the same time last year.
The future of net exports will depend on underlying trends in both output and consumption of
petroleum products. Future output will reflect both U.S. refinery runs and the production of
hydrocarbon gas liquids outside of refineries. Future domestic consumption will reflect prices,
economic activity, and policies such as fuel economy standards for both light- and heavy-duty
vehicles. So long as domestic output of petroleum products grows faster than their consumption,
net petroleum product exports will continue to rise.

Oil Price Drop Special Coverage
Oil prices steady but oversupply, China stock rout drag
REUTERS + NEWBASE
Crude oil prices were steady on Thursday, with U.S. contracts still down around 16 percent since
a peak hit in late June, as traders fretted about China's stock market rout, Greece's debt crisis and
a glut in supply.
Front-month U.S. crude futures CLc1 were trading at $51.65 per barrel at 0148 BST, unchanged
from their last settlement, but prices are down over 8 percent since Monday. Front-month Brent
crude LCOc1 was firmer, edging up 3 cents to $57.08 a barrel, but also down some 5 percent
since the end of last week.
"The China risks ... present danger for Australia and other economies which are leveraged to
commodity exports to China," Ole Hansen, head of commodity strategy at Saxo Bank, said in a
note."Oil is being pressured on multiple fronts, and China's equity wobble, the prospect of Iran's
re-entry to the market and low liquidity all add up to an extremely fraught environment. Oil needs
to establish a new range and we would see the WTI crude low around $50 with the upside capped
at $58."
China's securities regulator took the drastic step late on Wednesday of ordering shareholders with
stakes of more than 5 percent from selling shares for the next six months in a bid to halt a plunge
in stock prices that is starting to roil global financial markets.
The announcements came after China's stock market, which has lost a third of its value since
June, showed signs of seizing up on Wednesday, as almost half of the country's listed companies
scrambled to escape the rout by having their shares suspended and the regulators warned of
"panic sentiment" gripping investors.
Meanwhile, a surprise increase in U.S. stockpiles despite the peak demand American summer
driving season added to global oversupply as the Organization of the Petroleum Exporting
Countries (OPEC) and Russia produce at near record levels. Iranian exports could also resume at
full throttle if major global powers and Iran find a compromise in nuclear talks this week that could
lead to a lifting of western sanctions against Tehran.

Oil under $60 beyond 2016 suggests market rethinking shale
REUTERS
The almost 10 percent nosedive in headline oil prices this week has many hallmarks of a shocking
but short-lived slump, triggered by a confluence of external events and exacerbated by safety-
seeking investors and momentum-chasing traders.
By Tuesday afternoon, the crowded race to the exit was winding down, with prices recovering
from three-month lows as traders reassessed the factors they blamed for the worst slide in four
months: Greece's debt woes; China's stock market meltdown; talks with Iran over its nuclear
program; a stronger dollar; a rise in the number of U.S. oil rigs; a breach of key technical triggers.
Yet a deeper look at the market
suggests an important and more
lasting rethink may now be afoot:
longer-term oil prices, normally less
volatile and reactive than immediate
delivery, have suffered an almost
equally violent collapse, pushing
crude prices for 2017 to below $60
a barrel for the first time ever.
If U.S. shale drillers - the world's
new 'swing' producers - can still
turn a profit at below $60 a barrel,
then the fall in long-dated oil prices
may be rational. If not, as some
bullish market analysts worry, then
lower prices could be choking off
new supplies the world may need
as soon as next year.
"If you take the curve at face value,
it appears to be saying that U.S.
shale can grow ... if WTI stays
below $60 for three years. That
doesn’t seem very likely," Paul
Horsnell, global head of
commodities research at Standard
Chartered, said, referring to West
Texas Intermediate crude.
"One would guess that all those
companies that had been holding
back from cutting projects and jobs
over the past few months are not
going to hold on much longer, and
another shakeout will start. And it probably won’t be long before U.S. rig counts start to dive
again."

U.S. oil futures for December 2017 delivery have dropped by as much as $5 a barrel, or 8 percent,
in the past two days, an even deeper retreat than last November when OPEC's surprise decision
to maintain oil output despite a global glut sent markets into a deepening tailspin.
The more liquid frontline prices for delivery in August this year have fallen only slightly further this
week and are still several dollars above their trough from March. Longer-dated futures are
plumbing contract lows, testing the break-even economics for U.S. shale oil drillers.
The cause of this unusual tumble is still a topic of debate.
Some link it to a future shift in fundamentals such as the expected boost in Iran's oil exports next
year. Others say it may reflect the realization that oil industry costs are falling faster than expected
as activity slumps. A few wonder if it is an unusually large producer hedge, or a big macro-
economy fund trade unwinding.
IRAN, RIGS OR...
Longer-term oil futures are normally insulated from the speculative, short-term fluctuations and
factors that afflict immediate prices. Too illiquid to attract fast money, they tend to trade on more
strategic themes, whether a long-term bet on prices or a corporation seeking to hedge its price
risks.
Front-month oil futures have posted a daily change of more than $1 a barrel on 62 occasions this
year, trading in a range of over $20; December 2017 has moved by that magnitude only 18 times,
trading between $61 and $67 a barrel.
The fact that this week's activity has affected both ends of the futures curve in nearly equal
measure is unusual, says Credit Suisse analyst Jan Stuart.
"This isn’t a simple front-month correlation trade or a dip in demand," he says. "This is investors
who invest all along the curve picking up the ball and going home. That's what this looks like."
Some fundamental factors are also in play.
Negotiations over Iran's nuclear program, which may conclude this week in Vienna, have
increased the likelihood that a country that was once OPEC's second-largest producer will ramp
up exports as sanctions are eased - likely adding more supply to the market next year at the
earliest.
Others pointed to the latest U.S. rig count data released last Thursday, showing the first increase
in oil drilling since December. The addition 14 rigs was a bigger rise than expected.
The rise suggests that at $60 a barrel, "producers can ramp up activity given improved returns
with costs down nearly 30 percent and producers increasingly comfortable at the current
costs/revenue/funding mix," Goldman Sachs, which is predicting a deeper and prolonged oil
slump, said in a note on Monday.
A HEDGE TOO FAR?

Some suggested that the selloff, which began last week ahead of the U.S. Independence Day
holiday, may have provoked reticent oil producers to hedge, locking in far-forward prices for fear
they may fall much further.
Oil option volatility fell last month to its lowest level in seven months, making hedging relatively
cheaper for drillers who had locked in only 15 percent of their 2016 prices, according analysts at
Tudor, Pickering, Holt & Co.
The oil VIX index, a proxy for options pricing in the main oil ETF, has surged alongside oil prices
in recent days, rising from 33.8 to over 42, its highest since mid-April, in a possible sign of
increased demand to buy options protection.
Yet market sources saw little immediate evidence of a big hedge that could explain the price
move.
Trading volumes in the December 2016 and 2017 WTI contracts, which were the fourth and fifth
most-active in the market on Monday, was elevated, but not unusually so. The 2016 contract
traded just over 35,000 lots, double the 30-day average but a hair less than on July 1, data show.
"We have not seen a lot of activity in the last 24-48 hours," said John Saucer, vice president of
research and analytics at Mobius Risk Group, which advises companies on hedging. "We saw a
lot last month."

The shale recession is over. So what’s next?
Steven Kopits is the president of Princeton Energy Advisors in Princeton, New Jersey.
Last week, for the first time since last autumn’s oil price collapse, the number of US horizontal rigs
– those used for drilling shale oil – rose across the board.
They increased in all the major shale plays – the Bakken, Permian and the Eagle Ford – and on
balance in the other plays as well. And they did so in a relatively weak oil price environment, with
prices for West Texas Intermediate (WTI) averaging only $57 per barrel for the week.
So what happens now? The rig recovery may prove a blip, and modest rig declines may resume.
This is possible but unlikely. The rig count has been moving sideways for six weeks now, and the
most likely worst-case outcome is a steadying near recent levels.
Rig counts could also recover to a somewhat higher level and hold there. In Canada, for example,
horizontal oil rig counts, which had fallen to minimal levels, are four times higher than six weeks
ago. The number has now held steady over the past few weeks.
Overall, therefore, US rig counts are unlikely to fall from here, and instead are likely to recover,
although we don’t know whether the numbers will recover a lot, or only a little.
As a result of the collapse of rig counts, analysts widely expect that US oil production peaked in
March or April and will begin to fall. We can say with confidence that Bakken output is falling,
because the state government in North Dakota maintains timely and complete records. In Texas,

the matter is more problematic, because statistics are published with a two-month delay and face
heavy revisions for up to six months.
The US may be the most advanced oil economy in the world, but our statistics remain dreadful. As
a result, we don’t know whether total oil production is actually falling. My advisory firm’s estimates
of US production suggest that supply was flat in the past six weeks.
If US production follows the script, it begins to fall – and fall dramatically – over the next three
months, ending the year nearly 1 million barrels per day (mbpd) below the peak of late last year.
Even a modest recovery in rig numbers would not halt the decline, as shale wells have
extraordinarily high decline rates. A cut in rig numbers does not immediately result in declining
production. But the opposite is also true. An increase in rig counts does not immediately lead to an
increase in production. If analyst views prove accurate, we are facing a dramatic near-term
collapse in US oil production.
But maybe not. Some analysts believe that the US has a substantial shale oil resource, up to 60
billion barrels, available at $50 per barrel (WTI basis). If that were true, the US could comfortably
add 1 mbpd per year at prices of $10 per barrel lower than recently. In that case, US oil production
will not fall but instead will stabilise at current levels, and in a few months begin to grow again.
US shale oil would then be following the path of US shale gas, which continued growing at low
prices and rig counts owing to productivity gains, thereby successfully squeezing out Canadian
gas imports and a good bit of US conventional and offshore gas production.
In the case of oil, the majors such as Shell and Exxon would feel the pain. Our analysis suggests
the majors are still working under the assumption of $90-per-barrel oil. They need such a high
price to develop many of their exotic deepwater, Arctic, LNG and high-pressure and or high-
temperature projects. If US shales could begin to increase production at $60 WTI, the oil majors
would be in deep trouble.
And then there is the matter of the missing inventories. If the Paris-based International Energy
Agency (IEA) and the US energy information administration were to be believed, the world should
be struggling with 450 to 500 million barrels of excess crude and product inventories (above
normal commercial levels). However, independent analysts have been unable to actually find
these barrels in country stock reports.
We can say with some confidence that inventories complied by the Organisation for Economic
Cooperation and Development (OECD) are about 150 million barrels above normal levels. And
that is about it.
Outside the OECD, Iran appears to have 30 million barrels parked in tankers in the Arabian Gulf;
another 60 million barrels might be in various onshore storage tanks, for example, at Saldanha
Bay in South Africa. Notwithstanding, stocks for crude and major products appear about 40 million
barrels below anticipated levels in China, and Singapore stocks appear within normal tolerances.
Thus, some consultancies believe that excess inventories do not exceed 260 million barrels, with
about half of the total in the US alone. We at Princeton Advisors estimate the excess at about 315
million barrels.
If this is true, then actual demand must have been higher – much higher – than that recorded by
the IEA and US energy information administration. Indeed, 260 million barrels of excess inventory
suggests that world oil consumption in the fourth quarter of last year and the first quarter of this

year was 2 million barrels per day higher than the same period a year earlier. And this growth
increases to 2.7 mbpd in the second quarter, compared to a quarter two forecast of 1.1 mbpd
growth from the IEA. Demand appears to be running hot, and well in excess of virtually any
demand forecasts from the beginning of the year.
So where does this leave us? If US shales can resume their growth quickly, then oil prices may
stay subdued. However, if shale growth does not recover by September, then conventional non-
Opec production declines and surging demand are likely to push oil prices up, and by quite a lot.

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 09 July 2015 K. Al Awadi

NewBase 644 special 09 july 2015

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