New base energy news issue 875 dated 19 june 2016

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NewBase Energy News 19 June 2016 - Issue No. 875 Edited & Produced by: Khaled Al Awadi

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Opec’s woes could turn balanced market of IEA into shortfall Gulf Times + Bloomberg

The world’s most prominent oil forecaster, the International Energy Agency, anticipates near-equilibrium between supply and demand in global crude markets next year. If Opec members can’t resolve some massive output disruptions, that will turn into a significant shortfall.

World oil production in 2017 will very nearly match consumption, ending several years of oversupply, the Paris-based IEA forecast on June 14. For that to happen, the Organisation of Petroleum Exporting Countries would have to pump an extra 650,000 bpd over the year, according to Bloomberg calculations based on IEA data. That would require solutions to militant attacks in Nigeria, deep political divisions in Libya or an economic crisis in Venezuela.

“The IEA is highly optimistic in its assumption of elevated Opec supplies next year,” said Amrita Sen, chief oil analyst at consultants Energy Aspects Ltd in London. “Even though many view outages in Libya and Nigeria as unplanned, we would argue they are partly symptomatic of low oil prices and unlikely to be resolved any time soon.”

The supply and demand forecasts from the IEA, which advises 29 nations on energy policy, are important because they shape trading. The price of Brent crude has been on a roller coaster since 2014, with a global surplus driving it down 75% to a 12-year low of $27.10 a barrel in January, only to rebound to about $48 Thursday amid supply disruptions and unprecedented investment cuts.




By the end of next year, Opec will need to pump nearly 1mn barrels above last month’s production level to keep the market in balance, according to Bloomberg calculations based on IEA data. The agency doesn’t publish the Opec production level it assumes to calculate its balances and its press office declined to provide the figures or comment on the basis for its assumptions.

Fulfilling the IEA’s forecast would require Opec to overcome some major hurdles. In Nigeria, oil production has slumped to a 28-year low of 1.37mn bpd - about 480,000 below its full capacity, IEA data show. A militant group calling itself the Niger Delta Avengers has been targeting pipelines and other infrastructure in the African nation for several months.

Libyan output remains just a fraction of the 1.6mn bpd pumped before the toppling of Muammar Gaddafi in 2011. The nation pumped 270,000 bpd in May, a decrease of 80,000 from the previous month as a dispute between rival governments in the west and east halted tanker loading at the port of Hariga for several weeks. Many of the country’s oil fields and export terminals are in the hands of armed groups with competing interests.

In Venezuela, a severe economic crisis brought about by the slump in oil prices is making it difficult for the state oil company to pay its contractors for work necessary to sustain output, the IEA said. Output last month was 2.29mn bpd, the lowest since 2009, and the Latin American nation is on track for a drop of 100,000 bpd this year, it said.

Some additional output could be provided by Iran, which is restoring exports after nuclear-related sanctions were lifted in January. The Gulf nation will boost output to more than 3.7mn bpd next year, having pumped at a five-year high of 3.6mn in May, according to the IEA. Saudi Arabia, the world’s biggest exporter, could also increase output during the summer months to cover an increase in domestic demand, it said.

After two years of oversupply, the world’s most industrialised countries have more than 3bn barrels of oil in storage. This “enormous inventory overhang” reduces the prospect of “a significant increase in prices,” according to the IEA.

The agency estimates that inventories will decline very slightly in 2017, by an average of 100,000 bpd over the year. That narrow shortfall assumes Opec will pump 33.3mn barrels of crude a day, compared with the organisation’s May output of 32.6mn a day.




Qatar growth to stay healthy at 3.9% in ’16 and 3.8% in ’17 Gulf Times - Pratap John

Despite the decline in global oil prices last year, Qatar’s economic growth will remain healthy at 3.9% in 2016 and 3.8% in 2017, according to the Ministry of Development Planning and Statistics (MDPS).

Qatar’s real GDP growth is forecast to average 3.6% over 2016-2018, on the back of continued expansion in the non-hydrocarbon economy, which although moderating, remains strong, MDPS

said in its latest “Qatar Economic Outlook 2016 – 2018”. The non-hydrocarbon economy encompasses all economic activity other than upstream oil and gas production and other mining activities, it said. Construction will continue to expand through to 2018, though its pace of growth will ebb as existing projects are completed and no additional new assets are built.

The service sector will continue to post solid growth and is expected to be the largest contributor to growth, but its pace of expansion, too, will slow, if the foreseen moderation in population growth comes about in 2017 and 2018.

In 2016 and 2017, Qatar’s real GDP growth will be supported also by the hydrocarbon economy, which is expected to grow over the three years. The new gas field Barzan, after some technical delays, is now set to come onstream in the latter half of this year and reach full capacity in 2017, MDPS said.

The new Ras Laffan II condensates refinery, set to become operational in late 2017, will add to hydrocarbon output in 2017 and 2018. “But despite the uptick to overall growth over the near term, the contribution of the hydrocarbon sector to real growth, which is already low, will continue to diminish,” MDPS said.

In his foreword, HE the Minister of Development Planning and Statistics, Dr Saleh bin Mohamed al-Nabit said, “Over the projection horizon, the non-hydrocarbon sector will continue to account for most of the economy’s expansion. Real growth will be further supported by increased activity in the hydrocarbon sector, which will benefit from added output from the new Barzan gas project. “But as infrastructure investments plateau and projects are de-scoped, and as population growth slows, activity in the non-hydrocarbon sector will begin to taper, and overall growth will moderate to 3.2% in 2018.”

On the fiscal side, the minister noted that given lower oil and gas revenues and large expenditure outlays, the fiscal balance is anticipated to register its first deficit in over 15 years. The external current account balance is also expected to be adversely affected by lower oil prices and will register a small deficit in 2016, but the balance will return to positive territory in 2017 and 2018 as oil prices recover.




Morocco: Chariot Oil & Gas announces award of Mohammedia Offshore Exploration Permits I - III, offshore Source: Chariot Oil & Gas

AIM-listed Chariot Oil & Gas, the Atlantic margins focused oil and gas exploration company, has announced that its wholly owned subsidiary, Chariot Oil & Gas Investments (Morocco), has been awarded a 75% interest and operatorship of the Mohammedia Offshore Exploration

Permits I - III, Morocco in partnership with the Office National des Hydrocarbures et des

Mines ('ONHYM') which holds a 25% carried interest. The Mohammedia permits sit in the nearshore and cover an area of approx. 4,600km2 with water depths less than 500m. They are adjacent to the Company's Rabat Deep Offshore Exploration Permits on which Chariot recently announced success in partnering.

The Mohammedia area contains a number of proven and potential play systems. Chariot had acquired approx. 375km2 of 3D seismic data in 2014 in the precursor Mohammedia Reconnaissance licence from which the Company identified prospects in the Eo-Oligocene (EOP-1 & 2), Lower Cretaceous (LKP-1a,1b,2a,&2b) and the Jurassic (JP-2) with gross mean prospective resources for individual prospects ranging from 50mmbbls to 289mmbbls as audited by Netherland Sewell and Associates Inc.. The Jurassic carbonate shelf-edge system that makes up the JP-1 prospect in the neighbouring Rabat Deep licence has been interpreted to lie along the




western margin of the Mohammedia permits. This carbonate shelf-edge appears to act as a structural control on the overlying Early Cretaceous shelf margin with the LKP prospects resulting from the deposition of interpreted shallow-water deltaic clastics.

Both the Eo-Oligocene and Lower Cretaceous prospects have seismic attributes that could be indicative of hydrocarbons. Chariot has committed to the acquisition of 250km2 of 3D seismic data which will be acquired where the LKP prospects extend outside the current 3D seismic data.

The bulk of the Mohammedia area currently has little seismic coverage. The Company has also committed to acquire a minimum of 2000km of 2D seismic over the rest of the licence to identify the nature and extent of the play systems in this underexplored region. Both of these 2D and 3D seismic programmes are likely to be acquired in 2017.

Larry Bottomley, CEO commented:

'Chariot is pleased to be able to convert the Mohammedia Reconnaissance licence into exploration permits as a result of the technical de-risking gained from our 2014 3D seismic campaign in Morocco.

'The Company intends to mature the prospectivity in the Mohammedia permits through the acquisition of additional seismic programmes. We also have the potential to realise additional de-risking of the petroleum system from the drilling of the JP-1 prospect in the neighbouring Rabat Deep permits. Chariot has previously announced partnering on Rabat Deep in which the Company will retain 10% equity for a carry in JP-1 to a cap in excess of expected well cost which we anticipate to occur in 2017.

'We would like to thank the Ministry for their cooperation in securing this licence and we look forward to continuing to work with our partner ONHYM on progressing exploration over this area.'




MOL Group’s twelfth hydrocarbon discovery in Pakistan MOL

MOL Group has announced a new oil and gas discovery in the MOL operated TAL Block, Pakistan. This marks the 8th discovery in the block and MOL's 12th in the country. The Makori-Deep-1 exploration well reached its target depth of 5067 m on April 17, 2016. During testing, the well flowed oil and gas in Lockhart-1 formation at a rate of 2020 bpd and 900 boe/d

(5.4 million sft3/d), respectively. This discovery marks the 8th one in the TAL block. As the operating shareholder MOL is currently responsible for over 80 000 boe/d gross production. Its partners in the JV consortium are OGDC, PPL, POL and GHPL. MOL has a well-established track record of over 17 years in Pakistan and holds equity stakes in five blocks in the country. The current discovery is MOL's 12th over three different blocks (8 operated). Dr. Berislav Gašo, MOL Group’s E&P COO commented: “We are very proud of our 8th discovery in the MOL-Operated TAL block. This new discovery has derisked exploration in deeper fault blocks in the TAL block leading to new upside opportunities. Further, this new discovery will help to improve the energy security of the country. We are thankful to our JV partners

as well as the Government of Pakistan for their solid support. Exploration and development efforts in Pakistan are crucial building blocks of the success of MOL’s New Upstream Program, which aims at making MOL Group’s portfolio self-funding even in a low oil price environment.”




Pakistan: Cost of Gwadar-Nawabshah Gas Pipeline Revised Express Tribune

China Petroleum Pipeline Bureau has revised lower the estimated cost of laying the Gwadar-Nawabshah gas pipeline in Pakistan, Express Tribune, a local daily, reported Saturday.

The Chinese firm earlier estimated the contract price for the pipeline at $1.5 billion but the company has now lowered it to $1.3 billion in the financial bid given to Pakistani state owned firm Inter-state Gas Systems.

The pipeline would be 700km long with two compressor stations. It will carry the re-gasified natural gas (RLNG) from the proposed FSRU at Gwadar deep sea port. Earlier this month, Pakistan gave the green light to the Gwadar-Nawabshah LNG terminal & pipeline project. China will provide loans for both the projects equivalent to 85 percent of the cost of each project.

“The revised cost is even less than the cost at which gas utilities – Sui Northern Gas Pipelines and Sui Southern Gas Company – are augmenting their existing pipeline network to enhance the transmission capacity to 1.2 billion cubic feet per day,” an official told Express Tribune.

According to the official, Pakistan will negotiate a loan agreement with the Export-Import Bank of China that has already made an offer in this regard.

The South Asian nation has been facing severe gas shortage since last few years. The LNG terminal and pipeline project is expected to ease import of the fuel. Engro Corp currently operates Pakistan’s first FSRU through Engro Elengy Terminal Private Limited (EETPL).




US: Clean Power Plan accelerates the growth of renewable generation throughout United States

Source: U.S. EIA, Annual Energy Outlook 2016

EIA's Annual Energy Outlook 2016 (AEO2016) Reference case projects that natural gas-fired electricity generation will exceed coal-fired electricity generation by 2022, while generation from renewables—driven by wind and solar—will overtake coal-fired generation by 2029. The shift away from coal-fired generation to a combination of higher natural gas-fired and renewables generation and greater energy efficiency is expected to be accelerated by the U.S. Environmental Protection Agency's Clean Power Plan (CPP).

Notably, the share of natural gas-fired generation exceeded coal-fired generation in 2016, according to EIA's latestShort-Term Energy Outlook. However, in the AEO2016 Reference case, the natural gas-fired share of generation declines temporarily after 2016, then resumes rising in about 2020 and once again exceeds the coal-fired share in 2022 and throughout the rest of the AEO2016 projection to 2040.

Even without the CPP, significant growth in renewables generation is projected throughout the country, due in large part to Congress's recent extension of favorable tax treatment for renewable energy sources.

From 2015 to 2030, for the nation as a whole in a scenario where the CPP is never implemented, EIA projects that renewables generation will increase at an annual average rate of 3.9%, while natural gas generation will grow at 0.6% per year.

In the Reference case, which assumes the implementation of the Clean Power Plan, renewables and natural-gas fired generation grow at 4.7% and 1.6% annually from 2015 to 2030, respectively.




In the final version of the CPP, states with higher intensity levels generally have greater requirements for reduction of CO2 emissions.

EIA's analysis of the U.S. electricity market is divided into 22 regions, which in this discussion are further reduced to 9 regions shown above. The current generation mix across these regions varies considerably, with significant differences in the use of fossil-fuel, nuclear, and renewable energy sources.

Certain regions such as the Midwest/Mid-Atlantic, Southwest/Rockies, and Northern Plains—regions that are home to much of U.S. coal production—tend to have greater reliance on coal-fired electricity generation.

These regions have among the highest CO2 reduction requirements and are expected to have the largest shifts in their generation mix. In the Midwest/Mid-Atlantic region, a large decline in coal generation is offset by an increase in natural gas generation and relatively modest growth in renewable generation.

These projected changes are expected to result in a 26% decline in the Midwest / Mid-Atlantic region's emission rate—from 1,826 to 1,357 pounds of CO2 per megawatthour, the largest drop of any region in both percentage and absolute terms.

The Southwest/Rockies region is projected to see an expansion of renewables generation that is nearly twice as large as the decline in coal generation. In the Northern Plains region, a decline in coal generation is exceeded by a slightly larger shift to renewables generation, with smaller growth in natural gas generation.

Other regions, such as Texas, the Southern Plains, and the Southeast, rely more on natural gas-fired generation. The projected decline in these regions' coal generation is more modest, and they all are expected to see strong gains in renewables generation, with some additional growth in natural gas generation.




Finally, the Northeast region and California currently have almost no coal generation and meet most of their demand with natural gas generation, along with renewables generation in California and a mix of nuclear and renewables generation in the Northeast.

While the Northwest region does have some coal generation, it has the largest renewable generation total of any region because of its extensive hydroelectric resources. These regions have among the lowest emission reduction requirements, and as a result are expected to register small or no change in generation mix as a result of the CPP.

California sees strong growth in renewable generation by 2030 as a result of the state renewable targets. Similarly, the Northwest region is expected to increase renewables generation as well. The Northeast shows an increase in both natural gas and renewables generation by 2030, and a small decline in nuclear generation due to planned retirements.

The Reference case assumes that all states implement the Clean Power Plan using a mass-based standard that caps emissions from both existing and new plants, with allowance revenues rebated to rate payers. Because the plan allows flexibility in implementation approaches, EIA produced several alternative cases that consider how outcomes change with different implementation approaches, and in a scenario with tighter standards beyond 2030.

Compliance decisions by the states (as well as any future court decision that would vacate the rule) have implications for plant retirements, capacity additions, and generation by fuel type, demand, and prices. An AEO2016 Issues in focus article released early next week will explore the results of this analysis.




NewBase 19 June 2016 Khaled Al Awadi

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

Oil jumps 4 percent as Brexit fears ease, still down on week

Oil prices jumped about 4 percent on Friday, as a weaker dollar and less anxiety about Britain's

possible exit from the European Union encouraged investors to buy riskier assets.

Brent more than recovered the losses of the previous day, when it slid 3.6 percent, yet crude

futures still ended the week lower after daily declines from Monday through Thursday.

Brent crude futures' front-month contract LCOc1 settled up$1.98, or 4.2 percent, at $49.17 a

barrel.

The front-month in U.S. crude's West Texas Intermediate (WTI) futures CLc1 rose $1.77, or 3.8

percent, to settle at $47.98. It fell $1.80 in the previous session.

For the week, Brent was down nearly 3 percent and WTI dropped more than 2 percent.

The dollar fell nearly half a percent on Friday, retreating from its two-week high on Thursday that

had weighed on demand for greenback-denominated oil from the holders of the euro and other

currencies.

Oil price special

coverage




Britain mourned the death of UK member of parliament Jo Cox, a day after the vocal advocate for

Britain remaining in the union was murdered. Her death threw the country's referendum on its EU

membership next week into limbo.

Oil prices rose in spite of data showing U.S. energy firms adding oil rigs for a third week in a row,

suggesting higher production to come. Oil services firm Baker Hughes reported 9 rig additions this

week, the same as the week before and after the 3 rigs in the previous week. [RIG/U]

"People were looking for some trigger to sell the market down and the relatively small rise in oil

rigs didn't provide it, so everyone who was short crude had to rush and cover," said Scott Shelton,

broker at ICAP in Durham, North Carolina.

"Also, volume was lighter than usual, so whatever trades done carried the day for the bulls."

Volumes for Brent and WTI were just at around 200 million contracts each on Friday, versus the

nearly 300 million on Thursday for both, Reuters data showed.

Some analysts said with the UK's future in the EU still unknown until a vote next Thursday, oil

could come under pressure again on fears of a Britain exit, or "Brexit".

Julian Jessop, chief economist and head of commodities research at Capital Economics, told

Reuters Global Oil Forum an U.K. exit could drive Brent to as low as $40.

"It's mainly Brexit at the moment ... before people start to look at the more fundamental

oil/commodity drivers again," Hans van Cleef, senior energy economist at ABN Amro, said.




NewBase Special Coverage

News Agencies News Release 19 June 2016

Siemens, Gamesa Merge Units to Form World’s Biggest Wind-Turbine Maker ..Bloomberg - Anna Hirtenstein

Siemens AG and Gamesa Corp. Tecnologica SA agreed to combine their wind-turbine manufacturing businesses, creating a company that will dominate the industry and speed up consolidation triggered by competition and price pressures.

Europe’s largest engineering company will own 59 percent of the capital of the new business, Gamesa said in a statement on its website Friday. Gamesa, based in Zamudio, Spain, gets 41 percent and a 1 billion-euro ($1.1 billion) cash payment of 3.75 euros a share from Siemens. That represents 26 percent of Gamesa’s share price on Jan. 28 before the two disclosed their negotiations.

Together, the two would have about 69 gigawatts of turbines installed worldwide, putting them in a position to surpass Vestas Wind Systems A/S and General Electric Co. While worldwide clean-energy installations have hit successive records in recent years, a boom in manufacturing capacity and improvements in the technology have narrowed margins for making the machines. Companies are having to compete on a global scale, with Xinjiang Goldwind Science & Technology Co. of China taking the biggest market share last year.

“The combination of our wind business with Gamesa follows a clear and compelling industrial logic in an attractive growth industry, in which scale is a key to making renewable energy more cost-effective,” Siemens Chief Executive Officer Joe Kaeser said in a statement.

Shares Jump

Gamesa shares jumped 5.6 percent in Madrid, giving it a market value of 5 billion euros. Siemens rose 0.6 percent in Frankfurt trading. Vestas rose 3.6 percent in Copenhagen, partly because it won what could be its biggest-ever order.




The equity value of the wind businesses of Gamesa and Siemens would be 4 billion euros and 5.8 billion euros respectively, based on the market price of the Gamesa shares on Jan. 28 and an agreed exchange ragio, Gamesa said in a filing. That would give a combined equity value of 9.8 billion euros.

Gamesa Chairman Ignacio Martin said the move would boost earnings and have positive cash flows from its inception. “We will continue to work as before, albeit as part of a stronger company and with an enhanced ability to offer all of our customers end-to-end solutions,” he said in a statement.

Cost Cuts

The two have identified cost savings of 230 million euros that will be made within the next four years as a result of the deal. The combined company will have an order backlog of 20 billion euros, annual revenue of 9.3 billion euros and earnings before interest and taxes of 839 million euros. It will be based and listed in Spain, though the headquarters of the offshore-wind unit will be in Hamburg and Vejle, Denmark.

The combination will roil the rankings of the top wind turbine makers, which already were upset by the emergence of Goldwind as the top supplier by market share last year. The Chinese manufacturer pushed past Western rivals led by Vestas and GE. By market share, Siemens and Gamesa each had 5.3 percent of installations last year, according to Bloomberg New Energy Finance data. There combined 10.6 percent share would rank the new entity third behind Goldwind and Vestas.

Siemens pointed to the 69 gigawatts of turbines that it and Gamesa have installed worldwide, a measure that gives a sense of the revenue they may get from servicing machines. Based on that and Bloomberg New Energy Finance data for 2015, the new company would edge past its competitors. Vestas disputed the reading, noting that it currently has 75 gigawatts of installed turbines.




Gamesa’s network of installed turbines is attractive to Siemens, which has been trying to expand revenue from service contracts. The German company leads in machines designed for use offshore, while Gamesa specializes in onshore wind.

Europe’s turbine makers already have been consolidating. Last month, Nordex SE of Germany completed the purchase of the turbine-manufacturing assets of Acciona SA, another Spanish wind company. Vestas fired thousands of workers and closed factories to revive its profit after price pressures led to three years of losses that ended in 2014.

Deal’s Structure

The Spanish utility Iberdrola SA currently holds 20 percent of Gamesa and will have 8 percent of the combined company. The transaction is expected to be completed in the first quarter of 2017, assuming regulators approve.

Areva SA has a venture with Gamesa called Adwen that’s developing an offshore-wind turbine and has contracts to build seven wind farms off the French and German coastlines. Gamesa said Areva waved its contractual restrictions to allow the deal to progress and will receive options to buy or sell its stake in the venture over the next three months.

“We basically see a new kid on the block arriving to the offshore scene,” said Keegan Kruger, a wind analyst at Bloomberg New Energy Finance. “Siemens faces stiff competition from GE and from MHI Vestas,” which is a joint venture in offshore wind owned by Vestas and Mitsubishi Heavy Industries Ltd. of Japan.

Siemens Impact

For Siemens, the wind division is the smallest of its eight operational businesses, and also has the lowest profitability target.

The Spanish and German companies also complement each other in the markets they serve. Gamesa is strong in South America and India as well as being the biggest foreign supplier in China. Europe, the Middle East, Africa and North America meanwhile account for almost 90 percent of Siemens’s customer base, according to BNEF.

“As a leading wind power player especially in emerging markets, Gamesa is a perfect partner for us,” said Lisa Davis, member of the managing board of Siemens. “Teaming up will enable Siemens and Gamesa to offer a much broader range of products. The move will put Siemens and Gamesa in the best position to shape the industry for lower cost of renewable energy to the consumers."

C R




Nuclear power to ‘free up’ more oil and gas in GCC: Apicorp Energy Research …Gulf Times - Pratap John

Nuclear power would “free up” more oil and gas for export in the GCC region, Apicorp Energy Research said in a report.

On the other hand, net energy-importing countries such as Egypt and Jordan would be able to secure long-term energy and reduce their import bills by utilising nuclear power, it said.

In the face of rising electricity demand, Apicorp Energy Research said nuclear power should enable Mena states to “diversify their sources of energy and reduce their carbon footprint.”

“But the outlook is mixed. While six countries have nuclear projects under way, planned or proposed, raising power generation capacity by 39GW, three Gulf countries have cancelled proposed nuclear projects in the wake of the Fukushima disaster. Fiscal constraints are one of the major barriers to progress, and the expectation is that nuclear power will account for only 3% of Middle East electricity generating capacity by 2040,” Apicorp Energy Research said.

Sustained increases in electricity demand in tandem with continuing demographic growth have prompted a number of Mena states to consider alternative sources of power generation, including nuclear. Yet at present, nuclear power facilities with capacity of just 5.6GW are under

construction. Only a further 6.4GW are likely to come online by2030. The International Energy Agency (IEA) estimates that by 2040, the region’s nuclear industry will account for only 3% of electricity generation, with oil and gas accounting for 70%.

Several factors make the nuclear option attractive. Nuclear plants emit considerably less greenhouse gases compared with fossil fuel-fired capacity and help countries reduce their carbon footprint.




Cost competitiveness has improved in recent decades, allowing nuclear technology to become a serious component of energy diversification strategies. Nuclear also advances human capital and promotes employment in a new energy sector.

But development of the nuclear sector to a level at which it competes with oil and natural gas will be both complex and expensive.

Countries with ambitions to build nuclear power plants will need to find funding, attract human capital and put in place clear and stable regulatory frameworks.

Governments will need to prove to the global community that their nuclear programmes are peaceful and ensure public acceptance of their programmes.

Public acceptance in the region is generally higher than that in Europe, and in the UAE, this helped support the implementation of its programme.

According to Apicorp Research, nuclear projects require substantial upfront capital but exhibit lower operational and fuel costs over their lifetime- typically 50 years.

Upfront capital costs range from $3bn-6bn/GW of installed capacity, more than double the cost of equivalent coal- or gas-fired plants. Investment decisions are therefore heavily dependent on the availability of finance and government support.

Nuclear can be competitive against other sources of base load power. The levelised cost of electricity (LCOE) for nuclear increases at higher discount rates, given nuclear is capital intensive. At a discount rate of 3%, nuclear is more competitive than coal and gas. At 7%, nuclear remains competitive. Only at 10% does nuclear become less attractive.

While nuclear is often seen as a source of long-term power supply, this is contingent on the ability of project owners to secure large stocks of uranium.

“Currently, only four countries in Mena have proven uranium reserves. But, at an average price of $69/kg this year, production in the region remains uneconomical. Therefore, countries considering nuclear will have to rely on uranium supplied largely from outside the region,” Apicorp Energy Research said.

E D I T : R E Z A / C O N T R I B U T O R




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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 19 June 2016 K. Al Awadi




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New base energy news issue 875 dated 19 june 2016