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,

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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.




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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 [email protected] [email protected]

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

Business

Transcript of NewBase 644 special 09 july 2015