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NewBase 05 January 2016 - Issue No. 762 Edited & Produced by: Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
GCC’s desalination carbon footprint cut crucial to achieving water sustainability
Saudi gazette
GCC utility providers and businesses must invest in energy efficient water desalination to reduce
the carbon footprint and hefty expenses associated with increased power consumption, urge
experts.
Driven by the launch of the Global Clean Water Alliance, which was announced by Abu Dhabi’s renewable energy company Masdar at Paris-based COP21 last week, the message from experts to stakeholders in the water industry is loud and clear: a sustainable water future can only be
achieved if potable water is produced without compromising the environment.
The Alliance, an international coalition of more than 80 members, is aiming to reduce carbon emissions from desalination by up to 270 metric tons annually before 2040.
Speaking ahead of the upcoming International Water Summit (IWS) in Abu Dhabi, where developments in low-energy and carbon neutral
water production will form the core of the conference program, Dr. Ahmad Belhoul, CEO of Masdar, highlighted the interconnected relationship between water and energy.
“Propelled by population growth and urban development, demand for potable water will continue to grow exponentially in the UAE. Recognizing the critical link between water and energy, Abu Dhabi, through Masdar, is investing in advancing cutting-edge, technologies to improve the efficiency and to reduce the environmental impact of desalination processes in the UAE, and ultimately across the globe,” said Dr Belhoul.
“Water is a precious and crucial resource in ensuring our sustained economic and social growth. Developing innovative technologies that can sustainably source clean water is vital, not only for the UAE, but for the Gulf and many other regions of the world. Masdar, and our partners, are pursuing on-the-ground, tangible innovations that will lead to commercial solutions that can be rolled out locally, regionally, and globally.”
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In November 2015 Masdar launched the operational stage of its pilot program in Ghantoot, Abu Dhabi, which will see 1,500 m3/day of potable water produced over the next 15 months using four unique technologies that will demonstrate commercially-viable and energy-efficient solutions for renewable-powered desalination. The project aims to dramatically reduce the energy intensity of desalination.
Energy consumption for desalination in the UAE and Saudi Arabia is expected to increase considerably in line with rising water demand, almost tripling between 2006 and 2025, according to a 2013 study published in the International Journal of Thermal and Environmental Engineering.
In Saudi Arabia, the annual total energy consumption for desalination was about 48,000 gigawatt hours (GWh) in 2006 and is expected to reach just above 119,000 GWh by 2025. The figures for the UAE are equally staggering – annual total energy consumption for desalination was almost 65,000 GWh in 2006 and could nearly triple to more than 145,000 GWh by 2025.
However, energy efficient technology could save as much as 17 percent of electricity consumed for desalination in Saudi Arabia, and 16 percent in the UAE in 2025, according to the same research. And with more than $300 billion being invested in GCC water and desalination projects between 2012 and 2022, this energy-saving potential could soon become a reality.
Paddy Padmanathan, CEO of Saudi-based ACWA Power and a speaker at IWS 2016, explained that advances in technology are already enabling low-energy water production.
“Reverse Osmosis plants such as those in the US have achieved consuming low rates of energy, however a majority of desalination plants still operate at higher energy consumptions levels. This is generally because of the outdated technology used in these plants, which itself is the result of high capital costs involved in the implementation of new technologies,” he said.
Reducing the energy consumed by fossil-fuel powered desalination plants also leads to a considerable decrease in carbon emissions. Reverse Osmosis plants, for example, produce about 90 per cent less emissions when compared to traditional thermal desalination methods, such as Multi-Stage Flash.
This, along with developments in membrane filtration and solar-powered desalination methods, is forging a path to a sustainable water future for the region, Padmanathan pointed out.
“Although some of these technologies are still in their infancy, we have seen their potential, and there are extensive research and investments being made in the region towards reaping the
benefits of energy efficient water production. It is now up to all stakeholders in the water community to research, develop, and implement these new discoveries,” he said.
IWS will take place on Jan.18-21 at the Abu Dhabi National Exhibition Centre
and brings together world leaders, field experts, academia luminaries, and business innovators to accelerate the development of new sustainable strategies and technologies.
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Oman: Japan-led group wins Oman bid for $2.3 billion power project The National - LeAnne Graves
Oman wants to increase its power-generation sector over the next three years, adding two new gas-fired plants that could help meet 30 per cent of Muscat’s power needs. A Japanese-led consortium will develop two power plants fuelled by natural gas at a total cost of US$2.3 billion in northern Oman.
Mitsui & Company will take the lead to operate the Ibri and Sohar 3 power plants with its partners, Saudi Arabia’s Acwa Power and Dhofar International Development and Investment Holding (Didic).
The power produced from the completed plants will be about 3.15 gigawatts. The electricity will be sold to the country’s utility, Oman Power and Water Procurement Company (OPWP), for 15 years. “These power-generation projects represent one of the primary focuses of Mitsui’s infrastructure business,” the Japanese group said, adding that it would continue to bid for contracts in the area.
This is not the first time the trio have joined forces to generate power in Oman.
In March, the same players won the second phase of the combined cycle natural gas-fired Salalah independent
power producer (IPP) plant. The 445 megawatt project is already under construction and expected to be completed in two years. At that time, Acwa’s chief executive, Paddy Padmanathan, said that Oman was a strategic market for the company.
Acwa wants to expand within countries in which it already operates. That includes Oman. The Saudi company is growing more than 20 per cent year over year, with its current portfolio standing at about $27.5bn in 2015 with more than $10bn on the books to be added this year.
Energy consumption in Oman is expected to increase to 47 terawatts per hour (TWh) in 2021 from 25 TWh in 2014, according to a report by OPWP in March. “Increasing personal income, housing starts and continuing government investment in infrastructure projects are major contributors to continued high growth in electricity demand,” said OPWP.
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Morocco: Sound Energy enters into Field Management Agreement with Schlumberger for the Tendrara Licence,
Source: Sound Energy
AIM-listed Sound Energy, the European / Mediterranean focused upstream oil and gas company, has announced that, further to the memorandum of understanding and term sheet previously signed with Schlumberger, it has entered into a Field Management Agreement (FMA) with an affiliate of Schlumberger Oilfield Holdings in relation the Tendrara Licence, onshore Morocco.
Under the FMA:
• Schlumberger will provide integrated technical services, equipment and personnel to Sound Energy, Operator of the Tendrara Licence;
• Schlumberger will fund a significant proportion of the capital expenditure on the first three Tendrara appraisal wells, and of the development of the licence area thereafter; and
• Schlumberger will be granted an upside linked to production performance.
•
Field Management Agreement Schlumberger Funding As announced by the Company on 8 June 2015 as part of its entry into Morocco and Farm-in with the Moroccan Oil and Gas Investment Fund, the Company is required, in accordance with the terms of the Farm In, to fund 100% of the costs of the first three appraisal wells on the
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Tendrara Licence. Under the FMA, Schlumberger has now agreed to fund the following proportions of the first three Tendrara appraisal wells:
• 80% of the capital expenditure of the first Tendrara appraisal well;
• 75% of the capital expenditure of the second Tendrara appraisal well; and
• 75% of the capital expenditure of the third Tendrara appraisal well.
Sound Energy will continue to be required to fund the remaining costs on the first three appraisal wells under the Farm In.
Thereafter or, if earlier, on commerciality of the Tendrara Licence having been declared, Sound Energy and Schlumberger shall fund the Company's costs under the Farm In in equal shares - with each party funding 50% of the Company's participating interest costs under the Farm In.
Schlumberger Net Profit Interest
Under the FMA the Company has granted Schlumberger a net profit interest of half of the Company's interest (which equates to 18.75% initially increasing to 27.5% after the first well).
Schlumberger Services
Subject to such services being made available at fair market rates, Schlumberger will provide integrated technical and drilling services, equipment and personnel to the Company under the FMA. The Services will be funded directly by Schlumberger up to the maximum
Schlumberger funding commitment percentages described above. Schlumberger will also have a right of first refusal to provide additional services to the Company, as Operator of the Tendrara Licence, under the FMA.
The Geology and Activity History The Tendrara structure represents a continuity of the Algerian Triassic Province and Saharan Hercynian platform with the same basin shows as the tectono-sedimentary evolution in the Algeria Basins.
AGIP first explored the Tendrara structure in 1966 / 67 drilling two wells, both proved gas bearing but were not fully tested. In 1983 the Moroccan NOC, ONHYM (Office National de HydroCarbures et des Mines) further appraised the structure drilling a third gas bearing well. In 2000, MPE drilled SBK-1 in the adjacent Sidi Belkacem structure to further assess the Trias Argilo-Gréseux Inférieur (“TAGI”) reservoir, which proved to be gas bearing and tested successfully.
In total seven wells have been drilled in the permit, five have been gas bearing and two have tested successfully. Of the two successful test wells SBK-1 had a peak rate of 5.5 MMscft/d and TE-5 had flow rates of 1.5 MM scf/d.
In June 2015 Sound Energy farmed-in to the Tendrara license, partnering ONHYM and Oil & Gas Investments Fund ("OGIF").
Sound Energy, subject to regulatory approvals, will assume Operatorship of the Licence and take a 55% working interest. OGIF will retain 20% and ONYHM the remaining 25%. The 55% working interest will be secured in two tranches, with tranche one (37.5%) awarded on completion of the transaction and the second tranche (17.5%) secured once Sound Energy commits to the second exploration phase (which would include a second well).
Under the terms of the Farm-In Agreement, Sound Energy will pay 100% of the cost of three wells, of which only the first well would be a firm commitment.
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Tunisia: Gulfsands Petroleum granted 2 two year extension for the Chorbane Permit, onshore Tunisia.. Source: Gulfsands Petroleum
AIM-listed Gulfsands Petroleum has provided an update on the Chorbane hydrocarbon exploration licence, onshore Tunisia. The Company has announced that, following the favourable opinion of the Comité Consultatif des Hydrocarbures made in August 2015 to extend the duration of validity of the first renewal period of the Chorbane Licence by two years, the decision to extend has now been ratified by the Tunisian Ministry of Industry, Energy and Mines .
The decision of the Ministry was published on 22nd December 2015 in the Official Journal of the Tunisian Republic. The duration of the first renewal period is now extended until 12th July 2017 and, based upon the application to extend made by Gulfsands, has a minimum work obligation of 200km of 2D seismic and 1 exploration well.
The Chorbane permit covers an area of 1,940 sq kms in central Tunisia near the port city of Sfax and is principally an onshore permit. The Chorbane area is surrounded by several producing oil fields and extensive oil and gas infrastructure, and there exists a significant data base of legacy 2D seismic data within the permit area.
Gulfsands, as operator of the Chorbane Licence (100% working interest) has identified drillable onshore prospects for light oil and wet gas. The Company's best estimate net prospective resource bookings for the Chorbane permit are 44.2 million barrels of oil equivalent (unrisked).
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UK oil and gas fields increase production for first time in 15 years The Guardian - Sean Farrell
Government statistics for the first 10 months of 2015 show oil and gas produced on the UK continental shelf up 8.6% from a year earlier, the industry body Oil & Gas UK said. It added that, based on that number, it expected production for all of 2015 to be between 7% and 8% higher.
The result was better than the small i ncrease it had expected, the group said, but it warned that improving production this year would be hard after oil prices slumped to levels not seen since before the financial crisis.
Britain’s oil and gas output has more than halved in the last 15 years as accessible sources ran low and investment in new fields failed to keep up with demand. A fresh push to explore new areas of the North Sea in recent years led to new fields starting up in 2015.
Deirdre Michie, Oil & Gas UK’s chief executive, said: “In February 2015 we predicted a marginal increase in production for 2015, but the industry-wide focus on improving production efficiency coupled with investments of more than £50bn over the last four years to bring new fields on stream across the last 12 months is paying off and yielding a better result.”
Oil producers such as Shell, Centrica and BP have slashed investment and announced thousands of job cuts to adapt to crude priced below $40 a barrel amid slowing demand and a glut of oil. Many new fields in the North Sea were commissioned when oil was trading at more than $100 a barrel and, Michie said, there would be more job losses this year.
“The fact is that the value of our product has more than halved,” she said. “Times are really tough for this industry and for the people working in it. We will continue to see job losses as we move into 2016 and we must be thoughtful and supportive of our colleagues and their families who are being made redundant or who are at risk of being made redundant.”
Brent crude futures, the global benchmark, rose more than 3% on Monday after abreakdown in diplomatic relations between Saudi Arabia and Iran raised fears of supply restrictions. But the oil price has fallen from $115 in the summer of 2014 and some analysts believe it has further to fall.
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Turkey: Valeura Energy confirms natural gas discovery in its first Banarli exploration well Source: Valeura Energy Valeura Energy, a Canada-based public company, has confirmed a natural gas discovery in its first exploration wellBati Gurgen-1 on its 100% owned and operated Banarli licences in the Thrace Basin of Turkey, which flowed at an initial restricted rate of 3.4 million cubic feet per day ('MMcf/d') on a 24-hour production test.
The Corporation has advised that preliminary Q4 2015 net petroleum and natural gas sales in Turkey averaged 806 barrels of oil equivalent per day ('boe/d'), which was in line with annual guidance and included 4.8 MMcf/d of natural gas at an average price realization of approx. $9.90 per thousand cubic feet ('Mcf'), and 7.0 barrels per day ('bbl/d') of oil and condensate.
BANARLI EXPLORATION RESULTS (VALEURA OPERATED, 100% WORKING INTEREST)
As previously announced on December 17, 2015, the Corporation drilled its first two exploration wells on the 100% owned and operated Banarli licences in November and December 2015, with encouraging results. Since that time, completion and testing of the first well Bati Gurgen-1 and construction of tie-in facilities have been underway targeting first gas at the end of January 2016. Bati Gurgen-1 Well The Bati Gurgen-1 exploration well (Valeura 100% working interest) was drilled to a measured depth of 2,735 metres into the top of the Teslimkoy member of the Mezardere formation and was cased to a measured depth of 2,729 metres. Log analysis indicated 32 metres of aggregate net gas pay at an average porosity of 19.6% in multiple stacked sands in the Danismen and Osmancik formations. The well also penetrated several over-pressured, thinner and tighter stacked sands in the Mezardere formation.
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The main completion program consisted of perforating approx. 13 metres of conventional stacked sands in the Osmancik formation below 1,480 metres and carrying out a 24-hour production test.
Over this period, 3,448 Mcf of natural gas, 15 barrels of condensate and minimal water were produced at a stable restricted rate of approx. 3.4 MMcf/d through a 36/64ths inch choke and a final flowing wellhead pressure of 1,307 pounds per square inch. It is expected that the Danismen formation will be completed within one or two months after the well is on production to permit further performance monitoring of the Osmancik formation alone.
Prior to completing the Osmancik formation, a diagnostic fracture injection test was carried out in a short interval in the Teslimkoy at a depth of approximately 2,560 metres to measure formation pressure, permeability and fracture properties to support future exploration and frac design.
The test confirmed that the formation is significantly over-pressured at this depth with a pressure gradient of 0.69 pounds per square inch per foot ('psi/ft'), compared to a normal gradient of 0.43 psi/ft. This result is generally consistent with Valeura's interpretation of a potential pressure seal at a depth of approx. 2,500 metres across the Banarli licences, below which elevated pressures are to be expected with potential for a basin-centered gas play.
Although measured porosity and permeability in the Teslimkoy were encouraging, net pay was insufficient to warrant fracking and the Bati Gurgen-1 well was therefore plugged back to a depth of 2,540 metres before completing the Osmancik. However, these Teslimkoy evaluation results have provided encouragement to do similar diagnostic fracture injection testing in advance of a planned frack program in the Yayli-1 well, which was drilled 179 metres deeper than the Bati Gurgen-1 well and encountered much thicker aggregate net pay in the Teslimkoy. The Bati Gurgen-1 well is currently shut-in awaiting completion of the pipeline tie-in to the dehydration facility at the Gurgen-1 well (Valeura 40% working interest) located approx. 3.0 kms to the southeast on the joint venture lands acquired from Thrace Basin Natural Gas (Turkiye) Corporation ('TBNG') and Pinnacle Turkey Inc. ('PTI') (the 'BNG-PTI JV'). Yayli-1 Well The Yayli-1 exploration well (Valeura 100% working interest) was drilled to a measured depth of 2,914 metres into the Teslimkoy member of the Mezardere formation and was cased to a measured depth of 2,910 metres.
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Senegal: Cairn Energy announces successful Senegal appr. Well Source: Cairn Energy
Cairn Energy has announced the successful testing of the SNE-2 appraisal well offshore Senegal with positive results. Operations have been safely and successfully completed following drilling, coring, logging and drill-stem testing (DST). The well is now being plugged and abandoned.
Following this first successful appraisal well, resource estimates for the SNE field will be fully revised and announced after the results of the further appraisal activity. Evaluation of the extensive dataset collected is continuing, with preliminary analysis focused on the DST:
• DST over a 12 metre (m) interval of high quality pay flowed at a maximum stabilised, but constrained rate of ~8,000bopd on a 48/64” choke, confirming the high deliverability of the principal reservoir unit in the SNE-2 well
• DST over a 15m interval (~3.5m net) of relatively low quality 'heterolithic' pay flowed at a maximum rate of ~1,000 bopd on a 24/64” choke, confirming that these reservoirs are able to produce at viable rates and thus make a material contribution to resource volumes. Flow was unstable due to the 4.5” DST tubing
• Multiple samples of oil and gas recovered to surface from wireline logs and drill stem tests
• Confirmation of correlation of the principle reservoir units between SNE-1 and SNE-2 with the primary reservoirs occurring in the gas cap as predicted
• 216m of continuous core taken across the entire reservoir interval with 100% recovery
• Similar oil-down-to and oil–up-to depths seen in SNE-1 - 103m gross (95m in SNE-1)
• Pressure, log and seismic data indicate that the hydrocarbon column contains limited segregated reservoir-seal pairs within a continuous connected pressure regime
• Initial indications confirm the same 32 degree API oil quality as seen in SNE-1
The SNE- 2 well is located in 1,200m water depth and is approx. 100 kms offshore in the Sangomar Offshore block, reached the planned total depth (TD) of 2,800m below sea level (TVDSS). The well has been appraising the 2014 discovery of high quality oil in the SNE-1 well, some 3 km to the south.
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Bangladesh to Commence CBM Exploration at Jamalganj Coal Deposit NewAge + NewBase ( images )
Methane gas exploration work is expected to commence from Tuesday at Bangladesh’s largest coal deposit at Jamalganj, according to local English daily NewAge. Indian consulting firm Mining Associates Pvt Ltd would begin drilling of first exploration well at Jamalganj coal deposit, government officials stated. Petrobangla has engaged the firm to conduct the feasibility study. Mining Associates would drill three wells to examine the potential and reserve of coal bed methane (CBM), Petrobangla chairman Istiaque Ahmad told NewAge. It would require more studies before conceiving a commercial project there, he added. State owned Petrobangla and Mining Associates Private Ltd (MAPL) signed an agreement in June last year to work together to assess CBM exploration potential in Bangladesh.
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US oil "strippers" maneuver to keep pumping amid crude slump By Liz Hampton – Reuters
U.S. "stripper well" operators, the nation's smallest oil producers seen as most likely to succumb to the crude price slump, are hanging in tough, reducing the chances of near-term production cuts needed to rebalance the domestic oil market.
The conventional wisdom is that "strippers" would be the first to fold in the face of oil's slide below $40 given their tiny size - some may pump as little as few hundred dollars' worth of oil a day - limited access to capital and high costs compared with bigger, more efficient shale producers.
Yet interviews with executives and experts show those smallest, often family-owned, businesses are also among the most resourceful, keeping the oil flowing even as prices near 11-year lows and a growing number of their wells lose money.
While hopes for a rebound are fading, "strippers" are doing everything they can to keep their "nodding donkey" pumps working so they can hold on to land leases that give them access to oil reserves.
"The small operators of the stripper wells are pretty resilient," says Mike Cantrell, head of the National Stripper Well Association. "They've always made it through and will still make it through."
Stripper wells pump no more than 15 barrels of oil per day but together over 400,000 wells scattered across the nation's oilfields produce over a tenth of U.S. oil output, enough to affect the market supply-demand balance and prices.
Drawing analogies to the 1980s oil slump, some analysts had warned that half of stripper wells could shut if crude prices held below $40 a barrel , helping ease the supply glut and possibly underpinning the prices.
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The tenacity of the stripper well producers is challenging that view.
For example, Nelson Wood who runs Wood Energy, a family business founded by his parents more than 60 years ago, has laid off 14 of his 32 employees and closed 10 of 150 wells in the Illinois Basin, but so far the production is down only 4 percent.
He may have to shut more wells, based on electricity, labor, maintenance and salt water disposal costs, but said one key concern was meeting the requirements of oil and gas mineral rights. "We run some wells at a loss to keep the lease active," he said.
POSTAGE AND INSURANCE
To be sure, many of these mom-and-pop shops have already cut production to conserve cash and the longer oil prices remain low, the harder it will be for them to keep pumping.
Darlene Wallace, who inherited her company Columbus Oil after the passing of her husband over a decade ago, has shut in four of her 25 wells in Oklahoma, cutting about a third of production, and is now focusing on overhead costs.
Wallace says she has done everything from getting rid of a postage machine, which saves just $300 a year, to asking her three employees to cover 20 percent of their health insurance costs, which she estimates could result in annual savings of $10,000.
"I hate to do that to my employees, but we're all going to have to cut back," Wallace says.
Some stripper operators are even deferring necessary maintenance, others are turning to temporary workers to cut employment costs. Many are so small that their owners can roll up their sleeves and do the work themselves if necessary.
The stripper well operators who spoke with Reuters said many of their peers are taking similar measures to survive. Ponderosa Advisors, a Denver-based energy, agriculture and water
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consultancy, reckons debt-free companies can cover their operating costs even with oil below $35 a barrel. Some produce at a cost as low as $18.
That means prices can fall further before any major shut-ins.
In the meantime, many stripper operators are maneuvering carefully around clauses in their lease agreements to stay in the business. Most can only turn off their wells for a brief period without losing their rights.
In Texas, for example, the cessation period for which a well can get idled without the operator losing the lease is typically 60 to 90 days, according to Richard Hemingway Jr., head of the oil and gas practice at law firm Thompson & Knight.
"I have clients that are masters at working that," he said, referring to a technique in the industry known as "stop-cocking," where producers wait until the very final day of the cessation period before turning back on production.
Ken Hunter of Vaquero Energy, a stripper well company with several hundred wells in California, says in some cases operators may chose to produce from just a single well on a lease that includes up to 10 to remain in compliance.
Such techniques could lead to deeper production cuts if the crude downturn persists, but as long as stripper producers keep their leases they should be able to crank up output again once prices recover.
"We could easily fill the void with production from incremental drilling as soon as the price rebounds to even $50," according to Bernadette Johnson, a Managing Partner at Ponderosa Advisors.
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NewBase 05 January 2016 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil prices edge up after volatile session Reuters + NewBase
Oil prices edged up on Tuesday after a volatile session the previous day, with the impact of tension in the Middle East offset by worries over global economic growth.
Global oil benchmark Brent was up 22 cents at $37.44 a barrel by 0142 GMT, after hitting a three-week high of $38.99 on Monday as relations between Middle Eastern rivals Saudi Arabia and Iran deteriorated following Riyadh's execution of a prominent Shi'ite Muslim cleric.
But crude futures had erased those gains by the close on Monday as fears about the global economy outweighed concern about the dispute between Saudi Arabia and Iran, which looked unlikely to disrupt oil supplies immediately.
U.S. crude's West Texas Intermediate (WTI) futures were up 28 cents at $37.04. The tensions between Saudi Arabia and Iran "will likely reduce the likelihood of any collaboration between the two oil majors regarding oil output as Iran re-enters the international market once sanctions are lifted," ANZ bank said on Tuesday.
"This will further aggravate the oversupply situation in 2016."
Chinese stock markets extended declines on Tuesday after a 7-percent plunge the previous day caused trade to be suspended.
With Brent and WTI still trading some two-thirds below their mid-2014 highs, crude prices are likely to average around $50 a barrel amid the glut in global crude supplies, a Reuters poll of analysts showed.
Saudi Arabia's severing of diplomatic ties with Iran will not affect its efforts to secure peace in Syria and Yemen, and ties with Iran would be restored when it stops interfering in the internal affairs of other countries, said the kingdom's ambassador to the United Nations.
Traders said market intelligence firm Genscape reported a build of more than 480,000 barrels in Cushing crude supplies for the week to Jan. 1, after flooding in the U.S. Midwest caused temporary closure of a couple of pipelines.
U.S. commercial crude oil stocks probably dipped last week, while distillate and gasoline stocks likely edged higher, a preliminary Reuters survey showed on Monday.
Industry group American Petroleum Institute will release its data at 4:30 p.m. ET (2130 GMT).
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NewBase Special Coverage
News Agencies News Release 05 January 2016
Saudi Arabia vs Iran: The oil war that isn't coming CNBC - Everett Rosenfeld - Raheb Homavandi | Reuters
Armchair analysts have been predicting an oil price war between Saudi Arabia and Iran for a while now, and escalating tensions between the countries would seem to portend a major market disruption. But that war may never come.
Saudi Arabia announced Monday that it will sever all commercial ties with Iran, a day after the kingdom said it would cut diplomatic relations with Iran. Protesters stormed the Saudi embassy in Tehran earlier Sunday, and the country's supreme leader, Ayatollah Ali Khamenei, predicted "divine vengeance" for the Saudi execution of a major Shiite cleric.
Saudi Arabia is predominantly Sunni and home to many of Islam's most important holy sites, while Iran is the center of Shiite power for the Islamic world. The two countries are opposite poles in the Middle East's religious politics. Both also possess massive oil reserves.
Iranian protesters in Tehran hold pictures of Shiite cleric Nimr al-Nimr during a Jan. 4, 2016, demonstration against his execution by Saudi Arabia.
Responding in part to the acrimony, Brent crude jumped more than 4 percent Monday morning, but many market watchers predict that 2016 will be a year of significantly increased global supply (and therefore lower prices) as international sanctions against Iran come to an end and that country brings more crude to market.
Iran has already said that it plans to ramp up production, aiming to export an additional million barrels per day into global markets within six months — a move that its oil minister says is "not seeking to disrupt the market," but instead help Iran regain lost market share. And while most reports say Iran and Saudi Arabia could increase their production until the price is into the single digits, experts told CNBC that the two Middle Eastern powers won't take things that far.
"I think [Iran's] primary interest will be their own economic priorities," said Hani Sabra, the head of Eurasia Group's Middle East and North Africa practice. "And their desire to sell oil is not driven by a desire to drive the price down to hurt the Saudis; it's driven by a desire to make money."
According to Again Capital's John Kilduff, "the math is simple" to show that Iran would make more money selling fewer barrels at a higher price.
Moreover, if Tehran were interested in using oil to hurt the Saudis, it's unlikely it would succeed in the long run anyway, experts said. Riyadh has already signaled that it is hunkering down for an extended period of low prices by cutting subsidies and other government spending in an effort to shrink its 2016 deficit.
In addition to a low cost of production, Saudi Arabia also boasts extensive foreign currency reserves, and previously untapped opportunities in the international debt markets. "They haven't
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even gotten creative yet," Kilduff said, listing asset-backed bonds as an example of potential options for the kingdom.
"It's only a race to the bottom: Yeah, the Iranians have been beating their chests that they deserve to have no quota, as they missed a lot of the bloom years as a result of the nuclear sanctions, but the only alternative is to have a scorched earth where everyone is pumping as much as they can," Kilduff said. "And who is the last man standing? I wouldn't bet on the Iranians winning that one — I'm sticking with Saudi (Arabia) for that." And while Riyadh has the means to defend itself against an Iran-instigated price war, there's little to be gained by the Saudis if they start one. Richard Hastings, macro strategist at Seaport Global Securities, said any Saudi push for lower prices would be unlikely to deter Iran from bringing its product to market.
So oil may prove an imperfect weapon in the conflict between Riyadh and Tehran, but that doesn't mean the countries will let tensions ease: There are other economic (and military) means by which the rivalry can play out.
"Are Iran and Saudi Arabia competitors? The answer is yes. Is that competition intense? Absolutely. Is the level of the intensity of that competition going to increase? Yes," Sabra said. "But the idea that the primary tool for that competition is oil is false."
But even if geopolitical antagonism won't start a price war between the two countries, they are unlikely to cooperate with each other through the auspices of OPEC, where both countries are members, anytime soon: Experts were quick to tell CNBC that the oil cartel is all but dead in the current environment. "OPEC does seem to be a bit of a hollow tiger. It does seem to be a bit of a piñata," Hastings said. "It's just not what it was 30 years ago."
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Stubborn oversupply through 2016 to curb oil price recovery REUTERS
Crude oil prices are unlikely to rally much in 2016 as subdued demand growth looks unable to absorb rising supply from the likes of Iran and Iraq, even though non-OPEC output is expected to moderate, a Reuters poll showed on Monday.
The average 2016 price for benchmark North Sea Brent crude futures was forecast at $52.52 a barrel, $5.43 below the previous month's poll, according to the survey of 20 analysts. This is the seventh consecutive monthly Reuters poll in which analysts have cut their price.
In May, analysts forecast Brent to average $70.90 in 2016, but have been reducing their outlook ever since. Thirteen of the 18 respondents who participated in both the November poll and the most recent survey, conducted in December, cut their average 2016 price forecasts for Brent futures, which averaged $53.79 in 2015.
Oil prices have been hovering around 11-year lows after falling to their lowest since mid-2004 in late December, as near-record-high production looks set to feed a global surplus.
"Even if non-OPEC production (USA, Brazil, Canada) declines by 0.6-0.8 million barrels per day (bpd) in 2016, an increase in production from Iran and Iraq will continue to keep the market in an oversupply situation in 2016," CRISIL Research director Rahul Prithiani said.
Analysts said high inventory levels could persist well into 2017 as it may take a while to clear the overhang in unwanted stocks.
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"Demand growth will be impacted on account of the slowdown in Chinese demand growth, increase in efficiencies in the OECD (Organisation for Economic Cooperation and Development) countries, substitution from natural gas and removal of subsidies in developing countries," Prithiani said.
Analysts were not unanimous over whether lower prices would force the Organization of the Petroleum Exporting Countries (OPEC) to cut production.
A few believed OPEC might take some action if prices fell below $30, while others said there was no sense in the group cutting production unless demand collapsed significantly.
"The only scenario in which it makes sense for OPEC to cut production would be a collapse in demand, so a hard landing in China could potentially trigger such a move," Capital Economics commodities analyst Thomas Pugh said.
Analysts saw U.S. crude futures averaging $49.75 a barrel in 2016, compared with $53.73 forecast in November. West Texas Intermediate crude futures averaged $48.90 in 2015.
ABN Amro had the highest 2016 forecast for Brent at $65 a barrel, while Nomisma Energia had the lowest at $38.08.
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