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NewBase 20 March 2016 - Issue No. 811 Edited & Produced by: Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
UAE: As Abu Dhabi moves ahead with its solar ambitions, it is weighing more cost-effective technologies
The National - LeAnne Graves
With the Shams 1 concentrated solar power (CSP) plant marking its third anniversary this week, its operator said that other applications are now proving to be more efficient. The 100 megawatt
CSP plant is not cost competitive to other available technologies, such as solar photovoltaic (PV).
“The renewable energy market is, of course, changing and we’re always observing what is the most cost-competitive solution [for] that time and location," said Abdulaziz Al Obaidli, the acting general manager of Shams Power Company, the operating firm majority
controlled by Abu Dhabi’s Masdar.
Shams 1, a 100MW concentrated solar power plant in Abu Dhabi’s Western Region,
has won the Project of the Year Award from the Emirates Solar Industry Association
(ESIA). The Masdar project, which is being developed in collaboration Abengoa and Total, is the
largest solar power plant in the MENA region.
Locatied in Madinat Zayed, 120km southwest of Abu Dhabi, the plant extends over an area
of 2.5 km², with a solar field consisting of 258,048 parabolic mirrors. “We are delighted that
Shams 1 has received such a prestigious award,” said Yousif Al Ali, general manager of
Shams Power Company.
“This demonstrates the leading role that Masdar plays in the region’s renewable energy
sector and a realisation of the vision that our wise leadership has for renewable energy in the
UAE.”
When it begins feeding power to the Abu Dhabi grid early next year, the plant can generate
enough electricity to power 20,000 homes, and will offset 175,000 tonnes of C02.
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Shams Power’s original stakeholders included Masdar, Spain’s Abengoa and Total of France. Masdar last year acquired Abengoa’s stake and now holds 80 per cent. Total has the remainder. The plant last year fed 216 gigawatt-hours of power into the national grid – a 3 per cent increase from its target – which powered about 20,000 homes, said Mr Al Obaidli.
CSP was anticipated to take the region by storm when Shams 1 was being developed, with projects also cropping up in Morocco. As a result, Shams was expected to have two additional projects added.
Mr Al Obaidli said the land was originally reserved for three CSP plants, but times have changed and more cost-competitive options are now available.
Although he declined to give exact figures, Mr Al Obaidli said that the Shams 1 costs more than the average price of CSP. According to Abu Dhabi-based International Renewable Energy Agency (Irena), production costs for the technology range between 20 and 25 US cents per kilowatt-hour.
But Mr Al Obaidli pointed to the fact that Shams was one of the first CSP projects in the region. “It’s not at today’s electricity prices because when we built Shams, there was only one supplier in the world for mirrors. Now there are at least seven bankable mirror suppliers in the market."
In comparison, Dubai’s Mohammed bin Rashid Al Maktoum Solar Park, which uses PV technology, was awarded at a tender of 5.84 cents per kilowatt-hour.
While CSP costs much more than PV, it has other added benefits. PV technology must immediately feed into the grid any energy that it generates, whereas CSP can continuously power
areas even after the sun disappears thanks to storage capabilities.
Mr Al Obaidli said that the UAE is moving more towards PV because it is more cost-competitive than CSP and because of the electricity needs of the country.
He said that the UAE was looking to help manage its peak electricity times, meaning the middle of the day when the sun is the hottest and air conditioners are running at full power. And for this, PV technology is just the answer, as it can immediately feed more power into the grid.
“There are still countries and developers building CSP plants because they’re looking for more dispatchable base utility solutions and CSP is one of the best renewable energy solutions to provide stable dispatchable solutions," he said. Dispatchable power refers to being able to request a certain amount of electricity at any time, usually for places that struggle with their power supply or feedstock.
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Oman: DNO spuds first exploration well on Block 36 Oman Obverver - Conrad Prabhu
Norwegian oil and gas operator DNO has spudded its first exploration well in Block 36 in the southwestern part of the Sultanate, marking the start of an energetic exploratory effort targeting this promising concession in the prolific Rub Al Khali basin. The Hayah-1 exploration well was spudded last month, the company stated in a report of its financial and operational performance for 2015 covering all its licenses in the Middle East and North Africa region, including Oman.
DNO has a 75 per cent participating interest in the 18,000 sq km concession, which it acquired in 2013 via a farm-in agreement concluded with the previous operator, Allied Petroleum. The latter holds the balance 25 per cent.
Attention however has been primarily focused on its flagship Block 8 offshore Musandam Governorate, where the company operates Oman’s only offshore producing fields. Gross production from the Bukha and West Bukha offshore fields totalled 8,193 barrels of oil equivalent per day (boepd) last year, down from 15,678 boepd in 2014.
Among the factors blamed for the decline are well-failure and a lack of new drilling activity. Produced volumes from Block 8 in 2015 were 3.0 million barrels of oil equivalent (MMboe). Cumulative field production at end-2015 was 86.8 MMboe. As part of efforts to boost oil and gas production from the West Bukha field, DNO is weighing plans to drill an additional well, the company said.
Output from Block 8 comprised a roughly 50-50 mix of oil and gas in 2015. While the oil is sold to multiple buyers through a bidding process, the gas and LPG is lifted by a single customer. Oil sales accounted for roughly 95 per cent of the company’s total revenues, with the rest generated by gas and LPG sales last year. As of December 31, 2015, gross 2P (proven and probable) reserves within Block 8 have been estimated at 4.0 million barrels (MMbbls) of oil, condensate and other liquids, as well as 8.4 billion cubic feet (bcf) of marketable natural gas (1.5 million barrels of oil equivalent). Of this total volume, 2.7 million barrels of oil equivalent is net to DNO on a company working interest (CWI) basis.
Over the past year DNO has seen its portfolio of Oman assets halved to just two licenses — Block 8 and Block 36. This follows the relinquishment of Block 30 and Block 31 as part of an ongoing
“consolidation and
rationalization” of its portfolio, it said. In the MENA region, DNO also has production and exploration assets in Kurdistan and Yemen, as well as exploration assets in Tunisia, Somaliland and the United Arab Emirates.
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Qatar: Lower LNG costs to help Qatar stay profitable: BMI Gulf Times - By Pratap John
Qatar is one of the lowest cost producers of LNG in the world, which allows the country to remain profitable in the current pricing environment, an industry analyst has said.
Peter Lee, Asia Oil & Gas analyst at BMI Research said Qatar is the leading producer of LNG globally, exporting 103 bcm in 2015, equivalent to 82.7% of the emirate’s total natural gas exports.
Asia, he said, would remain the “dominant importer” of Qatari LNG over the decade. However, in a buyer’s market Qatar will have to show increased flexibility in its contract negotiations to maintain its position in the region, Lee told Gulf Times yesterday.
“Asia has historically been the largest off taker of Qatari LNG. However, in 2015, the volume of exports to Europe started to increase again, at the same time as Qatar reduced its exports to Asia,” Lee said. This move to Europe was, in BMI’s view, a response to weak demand in core North East Asia markets notably Japan and South Korea.
“We believe that Qatari LNG exports to Europe will remain elevated historically in the coming two to three years. In particular, the outlook for demand in Japan looks sluggish, as nuclear capacity comes back online and due to a dampened macroeconomic outlook,” Lee said.
The ability of Europe to absorb these excess volumes will be increasingly tested, due to weak demand growth in the European power sector, coupled with increased competition from new exporters, primarily the US. Post-2016, he said, Qatar does not have any new contracts coming into force and with 30.1bcm of contracts rolling off in the next ten years, and will have to start negotiating new contracts to secure long-term offtake.
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Despite the demand weakness in South Korea and Japan, BMI expects Asia to remain the dominant consumer of LNG, driven by strong growth in emerging markets such as China and India. As such, it will remain a key target for Qatar.
According to BMI’s Japan Korea Marker (JKM) forecast, the Asian LNG price benchmark will collapse in 2016 and 2017, as global oversupply drives down prices.
“We expect price weakness to remain weak for the coming five years, despite a modest recovery in 2019 and 2020. Price weakness creates a buyer’s market, eroding the negotiating power of Qatar. Reduced bargaining power will lead to terms that favour the Asian consumer, in particular through more flexible contract terms.
“Major changes we expect to occur include a relaxation of destination clauses, a shift to cargo-by-cargo contract models and more generous price re-opener clauses. In addition, a larger share of the contracts will be short and medium term rather than historically preferred long-term contracts,” Lee said.
‘Australia may overtake Qatar as largest LNG exporter by 2019’
Australia is set to “overtake Qatar” as the largest LNG exporter in the world by 2019, said Peter Lee, Asia Oil & Gas analyst at BMI.
Asked whether Australia would turn to energy-deficit and large countries such as India to seal supply contracts, Lee said, “If all projects under construction and in the proposed phase go ahead as planned, India’s LNG import capacity could double from around 25mn tonnes per year currently to more than 50mn tpy by 2018-19.
“However, India only has around 17mn tpy of supply contracts in place to 2019 (predominantly with Qatar). While typically India has relied on spot purchases to meet import needs, a lot of its un-contracted needs could be met via Australian supplies if the two countries can agree upon a favourable pricing terms,” he said.
Alongside the emergence of an increasingly loose spot market and ample opportunities for more efficient arbitrage, he said buyers would find it more attractive to sign short-term, smaller-volume deals with more flexible terms, rather than the traditional 20 to 25 year contracts.
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Saudi Aramco: After Motiva split, it aims to buy more U.S refineries REUTERS/ ALI JAREKJI (SAUDI ARABIA)
Saudi Arabia's national oil company wants to buy more U.S. refining and chemical plants to expand its footprint in the world's largest energy market once the break-up of its joint venture with Royal Dutch Shell Plc is complete, sources said.
Ending an often rocky nearly 20-year relationship, Shell and Saudi Aramco [SDABO.UL] announced on Wednesday plans to break up Motiva Enterprises LLC after almost two decades, dividing its assets and leaving Aramco with one plant, the nation's largest crude oil refinery, in Port Arthur, Texas.
Officials from Saudi Refining, the downstream arm of Aramco, told employees following the announcement that the state-owned firm was intent on buying more assets once the Motiva break-up is finished, according to five people who attended the briefing and asked not to be identified due to the sensitivity of the issue.
The plan comes as Aramco considers a landmark public offering of its vast downstream operations, which amount to nearly 5.5 million bpd of solely or jointly owned refining capacity around the world.
It also underscores the company's desire to expand its footprint in major markets, helping guarantee demand for its crude oil exports amid intensifying global competition.
The breakup is unlikely to have any immediate impact on sales of Saudi crude to the United States, Saudi Arabia's third-largest customer and a strategic security partner.
Under the deal, Aramco would gain full control of the 603,000 barrel-per-day Port Arthur refinery. Shell will get two smaller Louisiana plants, which have a combined crude oil refining capacity of throughput 473,00 bpd last year, according to U.S. government data.
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ROCKY MARRIAGE
Sources said this week's announcement was the result of years-long and sometimes fractious negotiations between the two partners over the future of their joint venture.
The two partners began talks in 2014, four years ahead of the expiration of the 20-year partnership agreement that became Motiva, the sources said.
Saudi wanted to take all three Motiva refineries and acquire Shell's chemical plant in Norco, Louisiana, but Shell refused to give up the Norco chemical plant and adjoining Motiva refinery that supplies it, they said.
"They want to acquire refineries," one of the sources said. "They want to get into chemicals. They want to expand and Shell doesn't."
Shell's reluctance to give up the refineries and chemical plant underscores the financial and strategic value of the plants as it pushes ahead with a large $30 billion asset sale program.
Shell expects to complete the split some time this year pending necessary regulatory approvals, according to an internal memo from John Hollowell, chief executive of Shell Midstream Partners LP, Shell's pipeline master limited partnership.
The companies intend to start running their respective independent businesses "as quickly, efficiently and safely as possible", it said.
The letter of intent was released on Wednesday because talks had progressed to the point that more-detailed discussions were necessary and those could not go forward without making the negotiations public, the sources said.
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GCC: $110b project-financed schemes in Gulf still on track despite oil slump Saudi Gazette
There are currently more than 120 project-financed schemes worth more than $110 billion either planned or under construction in the GCC as governments increasingly seek alternative methods of financing their project plans in light of falling oil revenues.
As the oil price fell in 2015, the value of project-financed schemes increased substantially to $14.3 billion compared with just $2.6 billion the previous year. With the oil price showing little sign of rising in the short term, this number is expected to continue growing in 2016.
According to data from regional projects tracking service, MEED Projects, the largest market for public projects backed with private sector finance in the Gulf region is Kuwait, which boasts schemes valued at just under $49 billion ranging from power plants and water and wastewater facilities to schools and tourism projects falling under the public-private-partnership (PPP) projects program.
The UAE is also a major player in privately-financed schemes, with about $35 billion of projects planned or under way. These include Dewa’s Sheikh Mohammed bin Rashid Solar Park, the RTA’s Union Oasis real estate scheme, and Fewa’s Umm Al-Quwain independent water project (IWP).
The four other GCC states have some $26 billion worth of privately-financed projects between them, including the Facility D independent water and power project (IWPP) in Qatar, Riyadh’s King Khalid International Airport Expansion Terminal 5, and Oman’s Sohar IWP.
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Alternative methods of financing public projects will be discussed and explored at the forthcoming MEED Financing Projects in New Oil Era conference taking place on March 23 at the Conrad Hilton Hotel in Dubai. A session on The Reality of Capital Availability in 2016 and Beyond will explore how companies will need to expand sources of finance as well as investment opportunities for infrastructure fund options in a low-price environment.
“The project finance model has been applied to power and water projects regularly over the past 15 years in the region, but it is only now with lower oil revenues that there is a concerted push to apply the model to projects in other sectors,” said Ed James, Director of Content & Analysis at MEED Projects.
“Governments are increasingly turning to innovative financing structures such as project bonds, sukuk issuances, and export credit agency financing to fund projects as revenues decline. By doing so, they can maintain spending on projects without impacting their balance sheets, a critical issue when state budgets are under strain from falling oil sales.”
Geopolitical & economic outlook for MENA countries will also be discussed, focusing on US shale oil production and its impact on the region’s oil markets, as well as future prospects of project financing and progress in the GCC.
MEED Financing Projects in New Oil Era is aimed at helping project sponsors to manage deficits and secure private finance, as well as assisting contractors deal with project slow down, contractor finance and cash flow issues while aiding investors and financiers to capitalize on the new borrowing needs of the region’s project owners.
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Iraq: Genel Energy announces Tawke field reserves updat Source: Genel Energy
Genel Energy notes that DNO, as operator of the Tawke field (Genel 25% working interest), has today published updated estimates of Tawke field reserves. The timing of DNO’s reserves update is in line with the disclosures made in the Company’s full year 2015 results on 3 March 2016.
At 31 December 2015, Tawke gross proved (1P) reserves are estimated by DNO ASA at 387.0 mmbbls, a 21% increase from the 319.9 mmbbls at year-end 2014, with the increase driven by improved confidence on primary recovery rates at the field. At 31 December 2015, gross proved plus probable (2P) reserves are estimated at 543.0 mmbbls, compared to 680.3 mmbbls at year-end 2014. The reduction from year-end 2014 reflects 2015 production of 49.3 mmbbls, technical revisions of 5.5 mmbbls and
a recategorisation of 82.5 mmbbls from 2P reserves to 2C contingent resources pending both a review of enhanced oil recovery options at Tawke and a decision to commit funds towards a field-wide redevelopment program. The updated Tawke 2P reserves compares to the Company’s previous estimate of 631.0 mmbbls, which was disclosed as part of the full year 2015 results. The 631.0 mmbbls figure was derived from DNO ASA’s 31 December 2014 Tawke 2P reserves of 680.3 mmbbls less 2015 gross production of 49.3 mmbbls. Incorporating the updated Tawke 2P reserves would result in pro-forma Genel Energy net 2P reserves at 31 December 2015 of 241.9 mmbbls. This compares to the 263.9 mmbbls of 2P reserves published as part of the Company’s full year 2015 results.
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Tanzania: Swala Oil & Gas (Tanzania) announces increase in estimated resource potential at its Kilosa-Kilombero licence.. Source: Swala Oil & Gas (Tanzania)
Swala Oil & Gas (Tanzania) has announced that Gaffney, Cline & Associates ('GCA'), an independent petroleum advisory firm, has completed its review of the resource potential of the Kilombero Basin, located within the Kilosa-Kilombero licence of southern Tanzania. Swala has a direct 25% interest in the Kilosa-Kilombero licence. Highlights • Increase in gross P50 Kito Prospective Resources from 151mmstb to 184mmbstb
(36.8mmstb net to Swala)*.
• Drilling at Kito on track for 3Q 2016.
• Four new leads identified in Kilombero with a further P50 Prospective Resources 148.9mmstb gross prospective resources (29.8mmstb net to Swala)*.
• Gross Prospective Resources at multiple reservoir levels aggregated by Swala, net of Government back-in rights.
• GCA has re-assessed the magnitude of the Kito prospect in the Kilombero Basin, as well as estimated the prospective resources of a further four leads in the same basin that were identified during the 2014 seismic campaign.
• The analysis was based on newer seismic data and increases the best estimate gross Kito prospective resources to 97 mmstb (19.4mmstb net to Swala on a working interest basis) in the Basal Sandstone and 87 mmstb (17.4 mmstb net to Swala on a working interest basis) in the Sequence 1 sandstone - see Table 1. GCA’s estimates of gross prospective resources in the additional leads are shown in Table 2. Swala has completed the tender process of the long lead items for the Kito-1 well and has issued invitations to tender to a number of regionally-based drilling contractors for submissions during March 2016. The technical review of the Pangani licence showed no structures of commercial interest and the Joint Venture has confirmed its desire to relinquish the licence to the Tanzania Petroleum Development Corporation.
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Norway: Statoil says oil field break even level should drop below $40 Source: Reuters
Norwegian oil major Statoil will push the average cost of new fields in its portfolio to a level below $40 per barrel, the company's chief financial officer told Reuters on Thursday.
In February, Statoil said extensive cost cuts had brought the break even cost of projects set to start production by 2022 down to $41 per barrel from $70 seen in 2013.
'All projects should move in the same direction with an average target of $41 for non-sanctioned projects. Below $40 should be a clear target,' CFO Hans Jacob Hegge told Reuters on the sidelines of an energy conference in Oslo.
'If you look at the pace of our cost reductions I think one could be very clear that we have not reached the final station yet. There is more to go,' he added. To cope with falling crude prices, Statoil has initiated a number of cost saving measures to be prepared for an extended period of weak markets.
In addition to cutting its capital spending plan to $13 billion this year from $14.7 billion in 2015, it has also set a cost cutting target of $2.5 billion on an annual basis. 'It's a target to stretch towards and which we are not entirely sure how to reach. We have set the bar high and people are working hard,' Hegge said when explaining the firm's progress.
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UK: North Sea oil industry down but not out, insists lobby group The Gurdian - Terry Macalister Energy editor
The oil industry is fighting off lame duck claims as forecasts from a financial watchdog show the once powerful sector needs subsidies from the Treasury for survival over the next five years.
The Oil & Gas UK lobby group insisted the offshore business was down but still vibrant, supporting hundreds of thousands of jobs and with £19bn being invested into new projects west of Shetland and elsewhere this year.
“This is a national resource that over 40 years has paid £330bn of taxes and never been subsidised. There is huge potential for hundreds of millions of pounds to be paid in future taxes as the oil price recovers,” a spokeswoman said.
But critics say the North Sea is rapidly turning into a dead sea and that it is
wrong for George Osborne to provide a £1bn package of tax breaks when carbon-producing fossil fuels should be buried not resuscitated.
The chancellor’s decision in the budget to abolish petroleum revenue tax and halve the supplementary charge on offshore operators came as the Office for Budget Responsibility forecast the industry would pay no tax this year.
And the OBR predicts that from 2017 the Treasury will be out of pocket by about £1bn annually as a once great cash generator turns into an industry that needs handouts. The oil and gas sector has been battered by a collapse in the price of commodities. Brent crude has fallen from $115 (£71) a barrel in June 2014 to its current level of about $40.
The OBR forecasts on oil tax revenues is based on a $44 crude price presumption, which some say is pessimistic. Oil & Gas UK declined to make predictions on prices. But North Sea annual tax revenues, which once climbed to more than £12bn, have also been hit by the gradual run down of production as wells run dry and the number of new finds dwindle.
In 2004, output from the UK was more than 2m barrels a day, but this dropped to 850,000 barrels by 2014. This latter figure compares with 11.5m barrels from Saudi Arabia and 11.6m from the new US onshore shale fields.
Richard Howard, from the centre right Policy Exchange thinktank, said it made sense to help the North Sea oil industry as the chancellor had done, as Britain would otherwise be even more dependent on foreign imports.
“The UK is still reliant on fossil fuels,” he said. “If the Treasury did nothing then you would just see the global companies that work there go elsewhere and the North Sea would decline even more quickly.”
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UK: faces years of negative oil sector revenues CNBC - Kalyeena Makortoff
The U.K. government's forecasting unit has slashed its oil income expectations for the next five years, predicting negative revenue from sector taxes this year as crude producers continue to struggle under low prices.
The latest figures released by the Office for Budget Responsibility (OBR) project U.K. oil and gas revenues to be "slightly negative," with losses set to total £10 million ($14 million) for the 2015-2016 fiscal year. Government earnings from the 2016-2017 fiscal year until 2020-2021 have been revised down by an average of £1.2 billion ($1.7 billion) each year.
That's compared to £2.2 billion in revenue in 2014 to 2015, and £11 billion in 2011 to 2012.
Abhishek Deshpande, an oil and gas analyst at Natixis, told CNBC by email that the downward revision "is not at all surprising," noting that oil prices have dropped 27 percent from where they sat at $48 per barrel as of the last OBR forecast in November, to $36 per barrel at the beginning of March.
The negative revenue forecast "is clearly showing the difficulty the oil producers in the North Sea face despite the talks on cost reductions," Deshpande explained. The OBR makes its calculations using futures prices for the first two years of its forecasts, and then holding those flat in nominal terms.
Oil prices have been under pressure thanks to many producers ramping up production despite a global glut. U.K. oil production, for example, rose by 12.8 percent in 2015 — a year when oil prices dropped over 31 percent.
The price crisis has also caused difficulties for resource-rich countries like Norway, which dipped into its oil-driven sovereign wealth fund for the first time in January since it was established in 1996. Norges Bank also downgraded its oil industry investment expectations Thursday morning, forecasting a 12 percent cut for 2016.
"We are also expecting oil companies in the U.S., particularly (those) that are not well hedged and in expensive basins, to have negative cash flows as well if (the) oil price does not recover fast," Desphande said.
Back in the U.K., the Conservative government is willing to exacerbate its own revenue losses to easing the tax burden on the oil and gas sector.
In the government's budget speech Wednesday, Chancellor George Osborne's announced a 35 percentage point cut to the petroleum revenue tax to zero, and reduced the supplementary charge to 10 percent. The move is expected to lower receipts by around 0.2 billion per year, starting from the period running 2016 to 2017.
It's a long-term view that the government hopes will boost sector returns. "There are only a few profitable firms in the sector," the OBR report explained. "Lower tax rates will boost the post-tax returns on oil and gas production, but we have assumed only a modest behavioral response. As noted earlier, the low oil and gas price environment will make it difficult for projects to clear investment hurdles," the report added. "This is likely to be the case even with lower tax rates."
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US: High production, low prices mean little change in natural gas storage capacity … Source: U.S. EIA, Monthly Natural Gas Underground Storage Report
High levels of natural gas production and relatively low natural gas prices are affecting markets for seasonal natural gas storage, including the value of additional storage capacity. For the second year in a row, no new natural gas storage facilities were added, and the slight changes, both positive and negative, at existing storage fields resulted in national storage capacity remaining essentially flat for the year. EIA measures natural gas storage capacity inNovember each year, which is typically when net storage withdrawals begin.
With elevated natural gas production, prices have been low and stable in recent years. Natural gas storage facilities have traditionally served as a physical hedge against high wintertime prices. Storage allows natural gas distributors or large natural gas consumers to buy and store less-expensive natural gas in the summer, and then to withdraw natural gas in the winter, when prices are typically higher. In recent years, however, natural gas prices have been exhibiting decreased seasonality, making some kinds of underground storage less financially attractive.
EIA uses two distinct measures of natural gas storage capacity:
Design capacity is the sum of the working gas design capacity at 385 active storage fields, as of November 2015, as reported in EIA's Monthly Underground Natural Gas Storage Report. Design capacity is based on the physical characteristics of the reservoir, installed equipment, and operating procedures particular to the site, and is often certified by federal or state regulators. Because of slight changes at existing fields and the deactivation of 10 facilities, design capacity declined slightly, falling 0.2%, from 4,665 billion cubic feet (Bcf) in November 2014 to 4,658 Bcf in November 2015.
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Demonstrated maximum working gas volume is the sum of peak volumes reported by the 385 active storage facilities in the Lower 48 states, regardless of when the individual peaks occurred over the five-year reporting period ending in November 2015. In the graphic below, this measure is compared to the five-year period ending November 2014. At the national level, the difference is small, increasing by just 0.1% from 4,336 Bcf to 4,343 Bcf.
In addition to geographical regions, EIA categorizes storage types based on geology. Traditional storage, such as depleted fields, provides the bulk of storage by volume, and it typically is filled during the spring, summer, and fall, and then is withdrawn during the winter.
Traditional storage is slow to fill and deplete, and holders of this natural gas generally prefer to not withdraw too early in the season because it cannot quickly be refilled for later use. However, an increasingly popular type of storage is salt cavern storage, which consists of leached caverns in salt deposits, mostly along the Gulf Coast.
While far smaller in volume, salt storage can be cycled in and out many times a year, allowing the stored natural gas to be withdrawn quickly to meet market needs, such as to provide heating during cold snaps or to take advantage of arbitrage when prices spike for other reasons.
Because of this seasonal usefulness, salt facilities in the South Central region saw a significant increase in demonstrated working gas volumes between November 2014 and November 2015, rising by 5.8%, as many salt facilities hit new peak levels in November 2015. By contrast, traditional storage in the adjacent Mountain region saw a significant decrease, falling by 6.3%, because a few facilities that reached peak levels in 2010 are no longer included in the five-year period ending in November 2015.
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NewBase 20 March 2016 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil hits 2016 high above $42 on production and demand outlook Reuters (Simon Falush) + NewBase
Oil rose above $42 a barrel on Friday, hitting its highest this year and extending a rally into a fourth week on expectations of a production freeze by major exporters, stronger seasonal demand and dollar weakness.
Brent crude’s front-month contract was up 77 cents at $42.31 a barrel by 1239 GMT, having touched a 2016 high of $42.40.
U.S. crude gained 84 cents to $41.04 a barrel after rising as high as $41.13. The benchmark had jumped by 4.5 percent to close the previous session at $40.20.
Oil prices have surged by more than 50 percent from 12-year lows reached in December, bolstered as the Organization of the Petroleum Exporting Countries (OPEC) floated the idea of a production freeze, boosting Brent from about $27 and U.S. crude from around $26.
Many analysts think there is still steam in the rally.
“We are leaving the period of low demand and starting to move toward the period when demand increases over the summer,” said Olivier Jakob, oil market analyst at Petromatrix at Zug in Switzerland.
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He added that the massive oil glut that had helped to hammer prices last year at last appears to be stabilising.
“We’re moving towards looking at an old surplus, rather than a new one being built up,” he said, adding that it is likely that Brent will stabilise around the mid-$40s.
Crude inventories in the United States increased by 1.3 million barrels in the week to March 11, to a record high of 523.2 million barrels, though that was a much smaller build than the 3.4 million barrels expected by analysts, the Energy Information Administration said on Wednesday [EIA/S].
Analysts said that dollar weakness was also lifting oil.
The dollar index is down 3.2 percent so far this month. A weaker dollar makes oil, which is priced in the U.S. currency, more affordable to holders of other currencies.
U.S. oil is heading for a fifth week of gains, while Brent is on course for a fourth weekly increase, the longest rising streak in about a year for both benchmarks. Oil is already up 17.5 percent in March, its strongest monthly gain since last April.
OPEC kingpin Saudi Arabia and non-OPEC producers led by Russia will meet on April 17 in the Qatar capital Doha in an effort to agree the first global supply deal in 15 years.
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NewBase Special Coverage
News Agencies News Release 20 March 2016
The U.S. Is Exporting Its Oil Everywhere Blommberg -= Javier Blas
Three months since the U.S. lifted a 40-year ban on oil exports, American crude is flowing to virtually every corner of the market and reshaping the world’s energy map.
Overseas sales, which started on Dec. 31 with a small cargo aboard the Theo T tanker, have been picking up speed. Oil companies including Exxon Mobil Corp and China Petroleum and Chemical Corp have joined independent traders such as Vitol Group and Trafigura Pte in exporting American crude.
The "growing volumes of exports" from the U.S. are now "spooking the markets," Amrita Sen, chief oil analyst at consultants Energy Aspects Ltd. in London, said in a note. The "flurry of export activity" is helping to support spot oil prices in the U.S. relative to contracts for later delivery, she wrote.
With American stockpiles at unprecedented levels, oil tankers laden with U.S. crude have docked in, or are heading to, countries including France, Germany, the Netherlands, Israel, China and Panama. Oil traders said other destinations are likely, just as supplies in Europe and the Mediterranean region are also increasing. Small Scale
That said, the U.S. is likely to remain for the foreseeable future a small exporter compared with OPEC giants Saudi Arabia, Iran and Iraq and non-OPEC producers Mexico and Russia. Ian Taylor, chief executive of Vitol, the company behind the first export, believes exports will remain a "very marginal business.”
Yet, tanker by tanker, overseas sales are growing.
Enterprise Products Partners LP, one of the biggest operators of oil ports in the U.S., told investors this month it alone expected to handle exports of crude and condensates -- a form of ultra-high quality oil -- of about 165,000 barrels a day during the first quarter, up almost 28 percent from the 2015 average. Cheaper Transport
One reason behind the rise in exports is cheap pipeline and railway fees to move crude from the fields in Texas, Oklahoma and North Dakota into the ports of the U.S. Gulf of Mexico. Another is that U.S. oil prices have been trading at a discount to Brent crude, allowing traders to move oil from one shore of the Atlantic to another at a profit.
The exports could relieve pressure on storage capacity in the U.S. after stockpiles rose to the highest level in official data going back to 1930. The tanks at the oil hub of Cushing, the biggest in the country and the delivery point for benchmark West Texas Intermediate crude, are 92.5 percent full, according to the Energy Information Administration.
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The risk is that the U.S. could shift the glut into Europe and the Mediterranean, where there are higher-than-usual loadings from the North Sea and the arrival of the first barrels of Iranian crude to the region since 2012.
Texas to Sicily
The export ban was imposed in the aftermath of a 1973 to 1974 oil embargo by the Arab members of OPEC, the Organization of Petroleum Exporting Countries. It crippled the U.S. economy and highlighted its dependence on imports.
Before it was lifted, the U.S. sold as much as 500,000 barrels a day overseas, from Alaska and a few other origins allowed under federal law.
Exxon in early March became the first major U.S. oil company to ship American crude from elsewhere, sending the Maran Sagitta tanker from Beaumont, Texas, into a refinery it owns in Sicily, Italy. Days later, Sinopec lifted on the Pinnacle Spirit tanker a cargo of U.S. crude, a first for a Chinese oil group.
Oil traders are starting to export American crude to store it overseas and profit from a market condition called contango. That’s where prices of oil for delivery today are lower than those in future months. Buyers with access to storage can fill up their tanks with cheap crude and sell higher-priced futures contracts to lock in a profit.
Gunvor Group Ltd., a commodities trader with main offices in Geneva, plans to ship 600,000 barrels of U.S. crude to a storage terminal in Panama. It’s then likely to ship the crude in Europe.
Oil traders are expecting more vessels to depart over coming weeks, with companies seeking to open new export routes from the U.S. West Coast and also moving barrels from new locations, including directly out of Cushing.
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