New base 525 special 25 january 2014

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NewBase 25 January 2015 - Issue No. 525 Khaled Al Awadi

NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE

US tight oil production and the future oil price By ; Morten Frisch

OPEC countries have said that the rapid build-up of US shale oil production is a major cause for the fall in the oil price. The three most important US producing areas for such oil are North Dakota’s Williston Basin containing the Bakken and Three Forks formations, Eagle Ford in South East Texas and the Permian Basin in West Texas. Based on this premise the critical question is: On what economic fundamentals are the investment decisions for the development and production of light sweet crude oil supply from these producing areas based?

North Dakota’s crude oil production is currently some 1.1 million barrels (bbl) per day. Due to the producing characteristics of tight oil wells, some 120 new wells will need to be drilled, hydraulic fractured and completed in North Dakota each month to sustain this production level. Using Bakken, the most important producing formation in North Dakota, as the example, finding and development (F&D) costs for new tight oil wells in sweet spots translate to a price requirement of some $20 to 25 per bbl over the producing life of a well. The cost of each such well when drilled from a pad as part of a multiple well program is some $9 million while the variable costs associated with the production, gathering, processing and transportation of the crude oil to markets are typically $17 to $23 per bbl. The investment cost of maintaining North Dakota’s oil production at the 2014 level in 2015 is therefore some $13 billion. It can be observed that the current one month forward price for West Texas Intermediate (WTI), the light sweet crude oil used as a benchmark for the pricing of Bakken crude is some $ 48 per bbl. This price level should be sufficient to pay both F&D and variable production costs in Bakken sweet spots. At this moment in time it is not possible to determine what the economic cut-off point for new Bakken sweet spot drilling is. US oil industry F&D cost are coming down due to the slowdown in the oil and gas E&P industry while oil pipeline transportation capacity from the tight oil producing areas are increasing, two developments which should lower this price point. Nearly 60 percent of the oil production from the Bakken area was in late 2014 transported to market in rail cars at a cost of up to some $18 per barrel. The economics of oil production from tight oil sweet spots in Texas’ Eagle Ford is in general better

Morten Frisch,MFC Gas UK




than for Bakken and Three Forks due to lower transportation costs from this producing area to refineries and oil terminal on the US Gulf Coast. The cost structure for tight oil operations in the Permian Basin in West Texas is, in contrast, likely to be more challenging than for Bakken due to a more complex geology. Oil production reports from operators to the Texas Railroad Commission in late December 2014 show oil production in Texas continuing to increase and this increase has over the last three years reached more than 2 million barrels a day with Eagle Ford and the Permian Basin being the two major contributors. Oil price hedges are crucial to the continued operation if not the survival of many independent US tight or shale oil producers. Unfortunately, very little is publicly known about companies’ forward oil price hedging activities. The best source for information about oil and gas price hedging positions is the producers’ quarterly financial reports, but fourth quarter reports for 2014 will first become available in late January or early February. However, the net short positions of oil producers and other non-financial companies in the US crude oil futures and options markets can be used as an indication of oil price hedging activities. According to Thomsen Reuters, these net short positions increased from 15 million barrels in August 2014 to more than 77 million barrels at the end of 2014. Many oil producers have been extending their oil price hedges or entered into new hedging positions during the last four months of 2014, and from the majority of these hedges they are likely to be paid a price of $60 per barrel or more, not only in 2015, but in many cases also in 2016. Sweet spot drilling and hedging are likely to prevent a dramatic fall in US tight oil production in 2015, although the number of active oil drilling rigs will fall as already can be observe in the West Texas Permian and the less productive areas of Bakken. When the oil price has spiked further down, all signs are that this will happen. The big question is: What will the lead time be for US tight oil producers to respond with ramped up drilling when oil prices again start to increase? In Eagle Ford, the time taken from application for a permit to drill a new well until this well is in production could be less than two months. This likely will alter the crude oil price cycle we have seen in the past. From the long five-to-seven-year price cycles set by for example major deep water offshore oil production projects, we are in the future more likely to see a short cycle or “yo-yo” type of effect around a much lower oil price level than what has been observed until the summer of 2014. Oil prices likely will be more stable and at a level well below the $100 per barrel producers had become accustomed to. All signs are that the world is in transition to a new oil market era with new-yet-to-be- determined oil price levels and dynamics. How long this new oil era will last is currently impossible to predict; most likely it will be minimum five years, but it could easily be ten to fifteen years, if not for a lifetime. Oil producers are facing big changes and uncertainties and only time will tell what these changes will be. — The writer is a senior partner of Morten Frisch Consulting, UK. He can be contacted at [email protected]. Website: www.mfcgas.com




Dubai:MD and CEO of DEWA receives CEO of First Solar (WAM) + NewBase –

Saeed Mohammed Al Tayer, MD and CEO of Dubai Electricity and Water Authority (DEWA), received a delegation from First Solar at DEWA’s headquarters, including Jim Hughes, CEO of First Solar, and Ahmed Nada, Vice President of Business Development for the Middle East.

This is one of a series of meetings that DEWA conducts with international organisations.

The meeting was also attended by Waleed Salman, Executive Vice President of Strategy and Business Development at DEWA.

Al Tayer welcomed the visiting delegation and stressed the importance of cooperation with partners in research and development and growing the renewable energy market.

He added that DEWA is working to promote Dubai’s position as a global hub for trade, finance, tourism and sustainability, and serve as a global model for achieving the highest standards of energy efficiency and renewable energy. DEWA is working to increase the share of renewable energy to achieve the Dubai Plan 2021 and the highest standards of excellence in DEWA’s services for its partners and customers.

The meeting included discussions about the Mohammed bin Rashid Al Maktoum Solar Park. First Solar built the first phase with a capacity of 13MW. DEWA selected a consortium, led by ACWA Power from Saudi Arabia and TSK from Spain, to build the second phase.

The capacity for the second phase was subsequently increased from 100MW to 200MW.

This was the lowest rate in the world for the production of solar-powered electricity. The Solar Park is one of the largest strategic projects in the world to use an Independent Power Producer (IPP) Solar Photovoltaic Power Plant. DEWA hired a consortium to oversee the selection process including KPMG as financial consultant, Lahmeyer as technical consultant and Norton Rose Fulbright as legal consultant.

DEWA is cooperating with First Solar to train engineers and develop their skills on the best solar energy technologies in collaboration with the University of Arizona in the United States as part of a strategy to train and develop professional expertise and promote Emiratisation.

The First Solar delegation thanked the MD and CEO of DEWA for the hospitality, the update about DEWA's work and projects and that DEWA welcomes cooperation with First Solar.

Earlier June 1013 ,HE Saeed Mohammed Al Tayer, MD and CEO of DEWA, and Georges Antoun, COO of First Solar, signed the MOU




UAE's Masdar inks deal to build Mauritania solar projects http://www.uaeinteract.com/news/default3.asp?ID=375

Masdar, Abu Dhabi’s renewable energy company, has signed a contract with Mauritania’s Ministry of Petroleum, Energy, and Mines, to deliver seven solar photovoltaic projects.

The projects with a total capacity of 12 megawatts will provide access to clean and reliable energy to seven towns across the African country, Masdar said in a statement. The projects, which are expected to be completed by the first quarter of 2016, will likely displace 6 million litres of diesel fuel annually and 16,134 tonnes of CO2 each year.

Each of the power plants will, on average, meet 30 percent of each town’s electricity demand. "Projects like these unlock significant economic and social benefits by providing more reliable and efficient local sources of electricity," said Dr Sultan Al Jaber, UAE minister of state and chairman of Masdar.

"Masdar is committed to showcasing how renewable energy can provide a cost-competitive solution to meeting rising energy demands and improving energy security for nations with isolated grids." The projects will add significant energy capacity to each of the seven towns, which include Boutilimit, Aleg, Aioune, Akjoujt, Atar, Al Shami and Boulenour.

"The solar projects which Masdar is delivering will demonstrate the valuable role renewable energy is playing in the social and economic development by positively impacting the lives of citizens, through the provision of clean energy at commercial rates for our country," said Mohamed Ould Khouna, Mauritania’s minister of petroleum, energy and mines.

Masdar will tender the project in the first quarter of this year and intends to engage local suppliers and contractors wherever possible, the statement said. This is Masdar’s second project in Mauritania, as the company delivered a 15MW PV plant in 2013 – the first utility-scale solar power installation in the country.




No 'significant' change in Saudi oil policy after king's death AFP + NewBase The chief economist of the International Energy Agency said Friday there would be no "significant" changes to Saudi oil policy following the death of King Abdullah. "With the death of the king, with the changes (in government), I do not expect any significant change in the oil policy of Saudi Arabia and I expect and hope that they will continue to be a stabilisation factor in the oil markets," Fatih Birol told AFP on the sidelines of the World Economic Forum in Davos.

"I hope they will continue to contribute to the stability of the oil markets ... especially in these days where we are going through difficult days," he added. The elderly King Abdullah died earlier Friday and was replaced by his half-brother Salman as the absolute ruler of the world's top oil exporter and the spiritual home of Islam. As the top producer in the Organization of the Petroleum Exporting Countries, Saudi Arabia has been the driving force behind the cartel's refusal to slash output to support oil prices, which have fallen by more than 50 percent since June. Oil prices surged Friday following Abdullah's death, amid uncertainty over whether the new king would maintain that policy.

Algeria Algeria may increase oil output to maintain revenues, says Yousfi

Algeria may increase oil output to maintain revenues, says Yousfi




Algeria:To increase its oil output & renewable energy projects production APS + NewBase

"Currently we are accelerating the development of dozens of deposits. We will consider the possibility of increasing our hydrocarbon output to raise the country’s revenues," Yousfi announced.

The minister was speaking on the situation of energy sector before the National People's Assembly (APN)’s Committee on Economic Affairs, Development, Industry, Trade and Planning.He stressed that the option of pumping more oil planned by his department is made necessary due to the need to maintaining the country’s revenues, which declined due falling oil prices.

"We ignore how long will last the crisis," he said while affirming that the country needs to fund its economic development without resorting to debt. Sonatrach produces 1.2 million barrels per day, which the ceiling set by OPEC to Algeria.

Speaking to the People’s National Assembly (APN)’s Committee on Economic Affairs, the minister said that in the coming weeks, the ministry will present an update of the renewable energy programme adopted in 2011 by the government.

The minister said that Algeria was able to complete this major project so to produce by 2030 more than a third of the country's electricity needs from renewable sources.

According to him, Group Sonelgaz in charge of executing this project has already completed the feasibility studies of the current programme of 12,000 MW and assessed the costs and the profitability of these projects.

The government has decided to diversify the country's energy mix by switching to solar energy despite its high costs ranging between DZD10-12 per one kilowatt against DZD2.5 per one kilowatt of electricity produced from gas.

The update of the renewable energy programme falls as part of the application of President’s measures taken last December for the rationalization of the domestic energy consumption and the development of the renewable energies.




Norway: Det norske commences drilling on the Ivar Aasen field Source: Det norske

The drilling rig Maersk Interceptor has commenced the drilling programme on the Ivar Aasen field in the North Sea. The campaign has a duration of three years and comprises a total of 15 wells in addition to three pilot wells. Det norske oljeselskap (Det norske) is the operator of the Ivar Aasen field (production licenses 001B, 028B, 242, 338 and 457).

The drilling programme for the Ivar Aasen field kicks off with the drilling of three pilot wells for further mapping of the underground. The drilling of pilot wells will be concluded by the summer of 2015.

'The three upcoming pilot wells are important to the licensees. They will enable us to retrieve important reservoir information at an earlier stage. This will create added value for the Ivar Aasen licence', says Inge Sundet, the drilling manager for Ivar Aasen. The drilling campaign on Ivar Aasen will be carried out by the drilling rig Maersk

Interceptor, the world’s largest jack-up rig. The rig has been contracted by Det norske for a period of five years, with an option of additional two years. The Ivar Aasen field is planned developed with a total of 15 wells; eight production wells and seven water injection wells. The Ivar Aasen field comprises three deposits: Ivar Aasen, West Cable and Hanz. Ivar Aasen is located west of the Johan Sverdrup field and contains 210 million barrels of oil equivalents. Production start-up is planned for the fourth quarter of 2016. The economic life of the field may be 20 years, depending on oil price and production trends. Det norske oljeselskap is the operator for the Ivar Aasen development, holding a 34.7862 per cent interest in the field. Partners are Statoil, Bayerngas, Wintershall, VNG, Lundin and OMV.




Bangladesh:KrisEnergy completes 2D seismic program in SS-11

Source: KrisEnergy

KrisEnergy has announced that the Binh Minh 2 vessel has completed a 3,146 km 2D seismic acquisition program in the SS-11 exploration blockoffshore Bangladesh. The 22-day program was conducted by CGG Services. Block SS-11 covers an area of 4,475 sq km in the Bay of Bengal over the Bengal Fan. The majority of the block lies in shallow waters of up to 200 metres.

Chris Gibson-Robinson, KrisEnergy’s Director Exploration & Production, commented: 'The existing 2D data sets were acquired in the mid-1970s and this program will provide higher resolution data to confirm existing prospects and leads and assess the overall prospectivity of the block. It will also help us determine potential locations for a planned 3D seismic program, to which we are committed under the work program obligations.' Santos Sangu Field is the operator of SS-11 with 45%. KrisEnergy (Asia), a wholly owned subsidiary of the KrisEnergy group of companies, holds 45% and Bangladesh Petroleum Exploration & Production Company Limited has a 10% working interest.




India: Energy subsidies prove drain on Indian economy The National + NewBase

Energy subsidies need to be addressed as a priority issue in India, according to the World Energy Council. Fuel subsidies have proved a major cost to India and have resulted in the country creating an unsustainable fiscal deficit over the years because of its heavy dependent on oil imports. India’s fuel subsidies reached an estimated 1.4 trillion rupees (Dh83 billion) in the financial year to March 2014, according to Moody’s.

But India has been gradually reducing its expenditure on subsidies for

consumers. Narendra Modi’s government in October ended

government-controlled diesel subsidies in an effort to cut spending. This followed the previous

government’s reduction of diesel subsidies. Petrol was deregulated in India two years ago. Subsidies on kerosene and propane are still in place.

“Energy subsidies, perceived to be a critical uncertainty in 2014, now have moved towards the need-for-action quadrant of the map,” the World Energy Council highlighted in a recent report. “The drop in uncertainty could be explained through the decision of the Modi government to continue with the diesel subsidy reforms initiated through the previous government. The cost of energy subsidies in India is planned to decrease to less than 0.5 per cent of Indian GDP by 2016. Hence there is a need for action to ensure that planned changes are being implemented accordingly.”

It says that India is one of the biggest energy consumers in the world, after China, the United States and Russia. India’s energy demand is rising an annual growth rate of 2.8 per cent, according to the organisation. Reducing subsidies is considered politically sensitive because such moves are often unpopular with the masses, who are also voters.

But because oil prices have come down sharply anyway, consumers have not noticed a negative impact from the removal of the government subsidies on diesel yet, which has actually come down in price compared to before the price controls were removed. Savings from fuel subsidies can be used in other ways, such as helping the poor in a more targeted manner and infrastructure spending, experts have noted.




Oil Price Drop Special Coverage

Oil producers in US not able to drill at $45 a barrel News agencies + Newbase Electrical power tycoon Boone Pickens predicted on Friday that oil selling prices would be again around $70 or $eighty a barrel by the fourth quarter of this calendar year. Oil producers in West Texas and North Dakota “are not able to drill for $forty five oil,” Pickens stated on CNBC’s “Street Symptoms.”

“In the very last 30 days they’ve dropped 300 rigs…. You are gonna get to an all-time superior on the inventory of oil, and it will be attained inside of the next six weeks, and then it will begin to drop.“ In December, Pickens forecast that oil costs would be back around $one hundred a barrel in twelve to eighteen months. On Friday, he said he stood by that call. With benchmark Brent crude rates down a lot more 50 percent from a year back, it may perhaps be difficult for some to envision these kinds of a bullish go.




But Pickens, the founder of BP Funds, said “we’ve obtained great numbers listed here. We failed to have a very good calendar year in a rough commodity dealing with electrical power, like we did, if we did not know what we are chatting about.” His organization noticed it is really commodity fund leap 10 percent last year. Oil prices traded narrowly mixed Friday. The US benchmark futures contract, West Texas Intermediate for delivery in March, fell 72 cents to $45.59 a barrel, a new, nearly six-year low. In London, Brent North Sea crude for March settled at $48.79 a barrel, up 27 cents from Thursday’s closing level.

Oil Rigs in U.S. at 2-Year Low as Bakken Drillers Bail Bloomberg + NewBase

Rigs targeting U.S. oil slid to the fewest in two years as explorers retreated from North Dakota’s

Bakken formation at the fastest pace since the nation’s shale boom took off.

The U.S. oil rig count dropped by 49 this week to 1,317, the lowest since Jan. 25, 2013,Baker

Hughes Inc. (BHI) said on its website Friday. The total count fell by 43 to 1,633. North Dakota,

home of the Bakken play that doubled its crude output within two years, lost the most rigs since at

least 2008 with prices under

$50 a barrel.

Oil rigs have dropped by an

unprecedented 258 in seven

weeks, threatening to end the

surge in domestic oil

production that has turned the

U.S. into the world’s largest

fuel exporter. The booming

production, out of shale

formations across the

country, has OPEC and other

foreign suppliers fighting to

preserve their market share. Eight hundred rigs may be pulled out of U.S. fields during the first

half of 2015, Penn West Petroleum Ltd. (PWT) Chief Executive Officer David Roberts said at a

conference Thursday.

“If you go down to operating cost levels in the $30-$40 West Texas Intermediate range, and stay

there, you will start to lose production in the highest-cost fields in North America,” Michael

Wittner, head of global oil research at Societe Generale (GLE), said Jan. 19 at a conference in

Calgary. “You’re already seeing the rig counts coming down. Drilling will come down. Well

completions will come down. In the end, it’s the steep decline rates that are going to do the job.”




Oil Prices

West Texas Intermediate for March delivery dropped 72 cents to settle at $45.61 a barrel on

the New York Mercantile Exchange on Friday. Prices rallied briefly the previous day after the

death of Saudi Arabia’s King

Abdullah.

The Organization of Petroleum

Exporting Countries, of which

Saudi Arabia is the largest

producer, has resisted calls to

curb production amid an

expanding surplus of global

supply. Saudi Aramco will

maintain its maximum sustained

crude-output capacity, Chief

Executive Officer Khalid Al-Falih said at the World Economic Forum in Davos, Switzerland, on

Jan. 21.

The slump in oil rigs has yet to put a dent in U.S. production, which reached 9.19 million barrels a

day in the week ended Jan. 9, the most in weekly data since at least 1983, Energy Information

Administration data show. Output was virtually unchanged last week.

Williston Basin

The Williston, a basin that stretches across parts of Canada and the U.S. Midcontinent and

includes the Bakken formation, lost more rigs than any other play in the country this week. The

count there is at its lowest since at least February 2011, Baker Hughes data show.

“The Bakken was late to join the others leaving the party,” James Williams, president of energy

consulting company WTRG Economics, said by telephone Friday from London, Arkansas. “It’s a

high-cost producer with some of the lowest oil prices in the country.”

Drillers including Antero Resources (AR) Corp. and BHP Billiton Ltd. (BHP) joined the droves

of companies curbing spending and canceling projects because of the collapse in oil prices.

BHP, the biggest overseas investor in U.S. shale, said Jan. 20 that it will cut the number of its rigs

there by about 40 percent. Antero Resources said the same day that it will cut its 2015 capital

budget by 41 percent.

Last week, Schlumberger Ltd. (SLB), the world’s biggest oilfield-services company, said it was

cutting about 9,000 jobs and seeking to lower operating costs at a unit that helps producers find oil

and natural gas.

“All of the major oil plays are losing rigs,” Williams said. “We’re falling off the cliff and we’re just

partway down.”




Oil price plunge to boost global M&A activity in 2015, says EY E&Y + NewBase

The oil-price collapse will facilitate increased global transaction activity in 2015 as companies revise and implement new strategies, according to a quarterly report on the industry published by Ernst & Young (EY).

“On one hand, upstream companies with strong balance sheets operating in low-cost basins will be well-positioned to not only weather the dip in prices, but also scoop up assets from those with less liquidity or more capital intensive assets,” Mitch Fane, EY oil and gas transaction advisory




services leader, said in the report. “At the same time, companies across the O&G segment will be pressured to review and reshape their portfolios to optimise capital and create higher returns.”

During fourth quarter last year, activity rebounded as total reported deal value increased 10% quarter-on-quarter and 67% year-on-year. However, total deal volume was down 39% quarter-over-quarter and 20% year-on-year. Global upstream deals followed a similar trend, as values rose 21% and volumes lost 22% from the previous year.

Midstream transactions continued to dominate with some 19 deals in North America alone for $56.6bn. Capital expenditures in 2015 from oil field services companies, meanwhile, may be cut as much as 20%-25% as companies seek to keep debt levels under control and slow production growth, the EY report said.

Upstream operators are expected to put significant pressure on oil field services supplies to cut costs. In response, oil field services firms will fight to retain market share through both innovation and consolidation.

Based on current forecasts of oil demand and non-Opec supply, in this year’s first half, the market is expected to need substantially less than 30mn bpd of crude from Opec, which is the amount the group has been producing and vowed to keep producing.

If Opec continues to produce more than 30mn bpd and there are no unexpected supply outages, the market could see a surplus of as much as 1.5mn-2mn bpd in the first half, EY said. By the second half, the price collapse is expected to cause US production growth to slow somewhat, but not to reverse. Seasonal demand increases will also play a role in the slightly improving supply-demand fundamentals, the report said.

The sharp decline in prices has also impacted global gas markets, as oil-linked LNG has fallen to levels on par with hypothetical US LNG export prices.Although US natural gas prices have weakened less than oil, they are still declining due to continued high production, weak early-winter demand, relatively high gas storage levels, and the decline in NGL (natural gas liquids) prices, the report said.

Due to their link to oil prices, global gas prices also declined in fourth-quarter 2014. Most notably, the oil-price collapse has minimised the advantage of spot-priced gas since oil-linked LNG trading prices are now essentially on par with hypothetical US LNG exports.

“Despite the weakening price spread, US LNG projects are still very competitive due to their low capital costs and the supply is attractive for flexibility and diversity,” said Deborah Byers, EY’s US oil and gas leader. “However, the LNG projects that don’t yet have contracts for their outbound gas will face much more pressure, as Asian buyers have less incentive to sign new contracts.” Refining margins declined in the fourth quarter, except in Asia, but 2014 was a solid year overall, EY said. Average annual margins across the globe were down slightly except in the US East and Gulf Coasts.

Refiners in the US Midwest had another strong year, EY said, although their advantage lessened as transportation bottlenecks were removed. Notional cracking margins on a New York Mercantile Exchange 3-2-1 basis recovered to around $25 for a barrel during the year before sliding again in the fourth quarter.





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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 25 January 2015 K. Al Awadi




Economy & Finance

New base 525 special 25 january 2014