New base 493 special 09 december 2014

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NewBase 09 December 2014 - Issue No. 493 Khaled Al Awadi

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

$10bn Ruwais refinery extension operational by new year The National + NewBase

The $10 billion extension of Ruwais refinery will be fully operational by the beginning of next year, which is part of plans to diversify the economy away from energy, an official at state-run refiner Takreer said.

Takreer has already started commissioning the new facility, which will nearly double the refinery’s capacity from the current 415,000 barrels-per-day and will process Abu Dhabi’s Murban crude oil grade.

Takreer signed contracts worth US$9.6bn in March 2010 with SK Engineering, Samsung and Daewoo to increase the Ruwais facility’s daily output. The expansion of the plant, located some 240 kilometres west of Abu Dhabi city, was originally slated for completion by the end of 2013.

“Refinery expansion supports Abu Dhabi’s plans toward diversifying its economy by investing in downstream capacity,” said, said Fareed al-Jaberi, vice president of supply division at Takreer at MEED’s Abu Dhabi Conference.

“There is growth in demand and we are committed to meeting the additional demand requirements. We are going to export very high quality refined products, which is another step towards meeting environmental specifications.”




Round Three of US$350 Million IRENA-ADFD Renewable Energy Funding Cycle Opens. Press Release + NewBase

In line with ADFD commitment to support renewal energy projects in cooperation with IRENA by extending concessional finance of up to USD 350 million over 7 cycles Abu Dhabi Fund for Development ( ADFD ) and the International Renewable Energy Agency (IRENA) have announced the opening of the third Funding Cycle for the Project Facility.

Applicants can now submit request for funding of RE Technology project in accordance with the "Guidelines for applicants". Countries that intend to apply for funding through the renewable energy development facility will have until February 18, 2015.

In support of this initiative ADFD has reduced their lending conditions to

encourage developing countries to take advantage of the Project Facility. Successful projects will enjoy funding rates ranging between 1-2 percent only. ADFD believes that this action would attract a wider range of renewable energy projects - many of which can be hugely capital intensive.

"We believe that the provision of renewable energy is an important and effective form of development aid," said Mohammed Saif Al Suwaidi, Director General of Abu Dhabi Fund for Development . "For that reason it is important that the recipients of the aid are able to fully realize the economic and social benefits of the clean energy projects delivered.

"Based on lessons learned from the first and second cycles we believe these new terms will significantly increase the facility's impact, and encourage developing countries to utilize this opportunity."

Projects approved for funding to date include solar, hydropower, biomass, wind energy and hybrid projects in Ecuador, Mali, Maldives, Mauritania, Samoa and Sierra Leone. The projects selected represent a diverse mix of renewable energy sources and innovative technologies that are replicable, scalable and will improve energy access in developing countries.

"The demand for concessional finance for renewable energy projects is high as demonstrated by the more than US$ 1.5 billion worth of loans requested in the first two cycles of the IRENA/ ADFD Project Facility," said Adnan Amin, Director-General of IRENA. "The lower interest rates now offered by ADFD make this an even more effective platform to support innovative projects, a diverse range of technologies and a wider geographic spread of countries."

ADFD pioneers the use of renewable energy as a viable and sustainable form of foreign aid that offers long-term social and economic benefits - through energy access - to developing countries. Recently, ADFDstrengthened its commitment to the deployment of clean energy for aid - delivering Samoa's first wind farm in partnership with MASDAR.

The recipient countries from round two of the facility will be announced during the IRENA General Assembly, which takes place during Abu Dhabi Sustainability Week, from 17-24 January, 2015.




Last January, the facility announced that six renewable energy projects in six separate developing countries would receive more than $41 million in loans. Once complete, the projects will provide energy to over 300,000 people and numerous businesses.

About Abu Dhabi Fund for Development

Abu Dhabi Fund for Development is a Government of Abu Dhabi national institution

established in 1971 to assist developing countries by providing concessionary loans to finance development projects in those countries, as well as direct, long term investments and contributions. Simultaneously, the Fund undertakes the management of government grants provided by the UAE through direct supervision and monitoring of project implementation and progress. The fund has provided and managed more than AED 64 billion since its inception until to date to finance 417 projects in 71 countries around the world. For more information about Abu Dhabi Find for Development, visit: www.adfd.ae

About the International Renewable Energy Agency (IRENA)

The International Renewable Energy Agency is mandated as the global hub for renewable energy cooperation and information exchange by 138 Members (137 States and the European Union). Roughly 35 additional countries are in the accession process and actively engaged. IRENA supports countries in their transition to a sustainable energy future, and serves as the principal platform for international cooperation, a centre of excellence, and a repository of policy, technology, resource and financial knowledge on renewable energy. The Agency promotes the widespread adoption and sustainable use of all forms of renewable energy, including bioenergy, geothermal, hydropower, ocean, solar and wind energy in the pursuit of sustainable development, energy access, energy security and low-carbon economic growth and prosperity. www.irena.org




UAE nuclear builder gearing for fourth reactor construction Enec + The National + NewBase

The UAE government is exploring options to fund its US$20 billion nuclear reactors and to store nuclear waste as the emirate of Abu Dhabi gears up to pour concrete next year on its fourth plant, a government official said on Monday.

The UAE, the first country in the Arabian Gulf to build nuclear reactors, is building four units in an area west of the capital to generate 25 per cent of its power from nuclear energy by 2020.

The project had been fully funded by the Government, with various finance options being considered for future work, said Fahad Al Qahtani, the group external affairs director at Emirates Nuclear Energy Corporation (Enec), the company building the reactors.

The UAE is looking to diversify its energy mix to lower dependence on fossil fuels. It is embracing renewable energy in addition to nuclear to achieve its target and meet power demand that is expanding by about 9 per cent a year.

In 2009, the UAE awarded the state-run Korea Electric Power Corporation (Kepco) the $20bn construction contract to build the four nuclear units by 2020. In 2012, Enec signed a $3bn fuel contract with six companies to source uranium for 15 years, starting in 2017. Uranium will not be enriched to a level exceeding 5 per cent, said Mr Al Qahtani.

Companies that may provide the uranium include France’s Areva, Russia’s Tenex, Canada’s Uranium One, the United Kingdom’s Urenco and ConverDyn of the United States. “They, either

ENEC announced in August that more than 55 per cent of construction on Unit 1 at Barakah, the site

of the UAE’s nuclear energy plants in the Western Region, had been completed. Image courtesy ENEC

First of 4 nuclear reactors 61% complete




independently or working together, will work on what we call sourcing the enriched uranium product,” Mr Al Qahtani said. “They will mine the uranium, convert it, enrich it then package it and then send it to Kepco, who will eventually package it in their assemblies and bring it to here.”

The UAE is currently exploring options to store nuclear waste and is looking at three scenarios. The first short-term option is using spent fuel pools, the second medium-term option is dry casks above ground at the site of the reactor, and the third option is having underground repositories.

Fuel leasing may also be considered, where spent fuel is recovered by a leasing company after being removed from the reactor core. Short-term fuel storage lasts 20 years and mid-term fuel storage lasts up to 100 years, Mr Al Qahtani said.

“The spent fuel quantity is so small,” he said. “The short-term and mid-term will suffice for use for a long time.” Enec has already started pouring concrete for its third unit after receiving approval in September from the Federal Authority for Nuclear Regulation (FANR).

The first unit is slated for operation by 2017 and unit two is due to enter commercial operation in 2018. Unit 1 one was 61 per cent complete and unit 2 two was 37 per cent complete, Mr Al Qahtani said added.

The UAE currently had no plans to further expand its nuclear programme, but may look at this option in the future, he said. “In the future if the government decides there is more demand, the company is of course ready, but for the time being we are focused on developing the four units,” he said.

“One of the things we did when we looked at the site is we looked at a site which is big enough for expansion if it ever happens.”




ALGIERS: Sonatrach maps out energy output expansion, to invest $80bn by 2019 Reuters + NewBase

Algerian state energy company Sonatrach said yesterday it will intensify its exploration efforts by drilling 125 wells a year and expanding its transportation network to help boost production over five years.

The North African Opec state’s crude oil and gas production has stagnated in recent years, stymied by a lack of foreign investors because of bureaucracy and security concerns, but neither Sonatrach nor the energy ministry provided details on incentives for potential oil partners. Sonatrach’s plans are crucial for a country that relies heavily on energy exports to pay for social programmes that have helped to maintain stability in an often volatile region. Domestic energy consumption is also growing.

Speaking at a North Africa oil and gas conference in Algiers, Sonatrach’s interim chief Said Sahnoun said the company would invest about $80bn by 2019 to boost production to 225

million tonnes of oil equivalent, adding that he does not expect lower oil prices to affect spending plans. Last year Algeria’s total production was 192 million tonnes of oil equivalent, including 121 million tonnes from natural gas, 54.5 million tonnes from crude oil and 9.5 million tonnes from condensate. “I remain optimistic about our energy output for the coming years and we are ready to work with all of our partners,” Sahnoun said.

The Sonatrach head said development plans included building up transportation network and a focus on less mature fields around Illizi, Berkine, Hassi Messaoud and Hassi R’mel areas, the APS state news agency said. However, there was no indication on what measures will be taken to attract investors that largely shied away from Algeria’s previous energy bidding round. Sid Ali Betata, head of Algeria’s hydrocarbons agency, said a new round was still being studied, with no date or further details available as yet. “There will be no new bidding round before we change the legal framework,” said one senior Sonatrach source who asked not to be identified.

Only four of 31 areas on offer were taken by foreign consortiums that included Spain’s Repsol, Royal Dutch Shell and Norway’s Statoil in Algeria’s first attempt to draw investors since a disappointing 2011 round. Algeria expects to start production at six gasfields in the next three years




reland: Europa Oil & Gas reports large prospects identified on its offshore Ireland acreage. Source: Europa Oil & Gas

AIM-listed Europa Oil & Gas has provided an update with respect to its FEL 2/13 and FEL 3/13licences in the South Porcupine Basin, offshore Ireland. Europa has now received a new prospect inventory from the operator of the licences, Kosmos Energy. The inventory is based on state of the art 3D seismic acquired in 2013 and includes the identification of a number of new, large prospects and leads on both licences. As a result, material changes have been made to the prospectivity previously mapped on the licences using historic 2D seismic data. Europa is currently preparing relevant data to initiate work on a Competent Persons Report for completion in H1 2015. Licence FEL 3/13




- Two prospects, named Beckett and Wilde, and one lead, Shaw, have been identified

- The new prospects have gross mean unrisked prospective resources of: 760 million barrels of oil (mmbo) for Beckett and 493 mmbo for Wilde

- These new prospects and leads replace the Kiernan prospect previously identified by Europa (see announcement dated 16 January 2013)

- Two new prospects, Doyle A and Doyle B, have been identified

- Gross mean unrisked prospective resources of: 123 mmbo for Doyle A and 69 mmbo for Doyle B

- These new prospects replace the Mullen prospect previously identified by Europa (see announcement dated 6 November 2012)

Further seismic analysis work is now being conducted to provide a definitive prospect risking and ranking. It is expected that this work will be completed in H1 2015 and will enable a decision to be made regarding next steps on the licences. This includes the possibility of detailed drilling planning and preparatory work to enable an exploration well to be drilled as early as 2016. Europa's CEO, Hugh Mackay said, 'This is a significant step forward for our exploration in Ireland. The prospect inventory has been completed by Kosmos and the early promise shown on historic 2D seismic data has been vindicated by the prospects identified on the new 3D seismic. Geophysical studies are now being performed to clarify prospect risk and ranking with a view to inform a drilling decision, expected to be in H1 2015. If positive this could lead to what could be a company-making well for Europa being drilled in 2016. More information will become available over the coming months as our plans mature and we look forward to updating the markets in due course. These are very exciting times for Europa.'




Canada:Petronas Approved for Canada Pacific Northwest LNG project PNW-LNG + NewBase

British Columbia Province Authorities have approved Petronas Pacific Northwest liquefied natural gas (PNW LNG) export terminal project and its related TransCanada Prince Rupert Gas Transmission (PRGT) pipeline project on the Canada west coast.

The joint venture Progress Energy Canada Ltd (Progress Energy) and its stakeholders, the national oil company (NOC) Petronas, Japan Petroleum and Exploration Corporation Ltd (Japex), Indian Oil Corporation Ltd (Indian Oil) and Petroleum Brunei made a major step forward for the construction of one of the largest LNG export terminal project to be built on the Lelu Island, near Prince Rupert in BC. In 2013, Petronas, Japex and Petroleum Brunei acquired the Calgary-basedProgress Energy.

In 2014, Petronas sold 15% to China Petroleum & Chemical Corporation (Sinopec) and 10% of its stakes to Indian Oil so that currently the working interests in Progress Energy are shared as following:

- Petronas 62% is the operator - Sinopec 15% - Japex 10% - Indian Oil 10% - Petroleum Brunei 3%




In order to supply this Pacific Northwest LNG project with natural gas, Progress Energy and its partners in the North Montney joint venture (NMJV) explored and developed natural gas reserves in the Northeast ofBritish Columbia, along the Province of Alberta. At the end of 2013, Petronas and its NMJV partners declared to have accumulated 8.35 trillion cubic feet (tcf)of proven and probable (2P) reserves of natural gas between the Montney Basin in BC, the Deep Basin and the Foothills in Alberta.

In addition, Petronas and its NMJV partners are targeting to delineate 65 percent of 24.7 tcf contingent resources. With these shale gas reserves in development in Alberta and British Columbia, Petronas is planning to build the Pacific Northwest LNG export terminal project in two phases.

The PNW LNG Phase-1 project should include:

- Utilities and power generation - LNG Trains 1 and 2 - Gas Inlet system - Gas Treatment facilities - Offsites - Storage and offloading facilities - Marine and jetty Then in a second phase Petronas would add the Pacific Northwest LNG train 3. Each LNG train should have a capacity of 6 million tonnes per year of LNG.

In May 2013, Petronas and its partners selected three teams of engineering companies to

organize a competitive front end engineering and design (FEED) in order to be proposed the most cost effectiveengineering, procurement and construction (EPC) contract for PNW LNG Phase-1 project.

The costs estimates returned by the engineering companies in competitive FEED for Pacific Northwest LNG Phase-1 project are significantly above the budgeted $11.4billion capital expenditure leading Petronas and its partners to revise costs. As a consequence Petronas and its PNW LNG partners Japex, Petroleum Brunei and Indian Oil will postponed the final investment decision (FID) for Pacific Northwest LNG Phase-1 project EPC contractfrom the end of 2014 to mid 2015 as they still target the first LNG shipment from Lelu Island in British Columbia by 2019.




U.S. nuclear plants require life extension past 60 years to operate beyond 2050 U.S. Energy Information Administration, based on U.S. Nuclear Regulatory Commission

When nuclear power plants are built, the Nuclear Regulatory Commission (NRC) has the authority to issue initial operating licenses for a period of 40 years. Beyond that, the reactors need license renewals, and the NRC has granted 20-year license renewals to 74 of the 100 operating reactors in the United States. These reactors may now operate for a total period of 60 years. They represent a cumulative capacity of a little more than 69,000 megawatts (MW). The NRC is currently reviewing license renewal applications for an additional 17 reactors, and expects to receive seven more applications in the next few years.

With the bulk of the existing nuclear fleet licensed before 1990, nearly all existing reactors will be more than 60 years old by 2050. Unless a utility applies for and receives a Subsequent License Renewal (SLR) that could further extend the operating lives of their reactors up to 20 additional years, the reactors will not generate power beyond age 60. Although no applications for an SLR have been submitted, several utilities are evaluating whether to apply for one, including Dominion Resources for its Surry Power Station Units 1 and 2 in Virginia (current license expiration dates of 2032 and 2033) as well as Exelon for its Peach Bottom Atomic Power Station Units 2 and 3 in Pennsylvania (current license expiration dates of 2033 and 2034). From a regulatory perspective, the NRC determined in August 2014 that existing license renewal regulations were sufficient to support the SLR process. The NRC's determination was supported by the May 2014 findings of the NRC's Advisory Committee on Reactor Safeguards, which stated that the current NRC license renewal framework would support SLR.




In making the decision to extend the operating lives of nuclear reactors beyond 60 years, the NRC will consider the long-term safety and security of continued reactor operation. In addition to the NRC, the U.S. Department of Energy, through its Light Water Reactor Sustainability Program, is one of several organizations studying the effects of aging on nuclear power plant systems, structures, and components. Other industry groups involved in studying SLR include the Electric Power Research Institute and the Nuclear Energy Institute. International groups, such as the International Atomic Energy Agency and the Organization for Economic Cooperation and Development's Nuclear Energy Agency, are also involved in addressing life extension issues in support of nuclear power plants around the world.

U.S. utilities already make significant investments in maintaining and upgrading the current fleet of U.S. nuclear power plants to ensure safe, secure, and reliable operation throughout their 40- or 60-year lifetimes. The Electric Utility Cost Group estimated that the industry invested $6.4 billion in capital projects to upgrade and maintain nuclear power plant systems during 2013.




Oil Price Drop Special Coverage

Brent crude slips as Morgan Stanley slashes forecast to $43/B The National + NewBase

Brent crude took a further tumble on Monday after another major forecaster cut its price expectations for next year, adding to the bearish sentiment for oil markets. The investment bank Morgan Stanley slashed its outlook and offered a worst-case scenario of the benchmark falling as low as US$43 a barrel in the second quarter. It revised its earlier estimate for next year to $70 a barrel from $98 and lowered its 2016 outlook to $88 a barrel from $102.

Brent for January settlement declined as much as $2.30 to $66.77 a barrel on the London-based ICE Futures Europe exchange on Monday, the lowest intraday price in more than five years. It slumped 18 per cent last month, a fifth straight decline.

Industry experts expect oil prices to remain below $70 as the battle for market share between US producers and Saudi Arabia continues to take centre stage. BNP Paribas, Credit Suisse, UBS and Barclays have all cut their forecasts since Opec’s meeting last month when it maintained output amid oversupply.




The head of Kuwait’s state oil company said there was no likelihood of a rebound any time soon, forecasting prices to remain around $65 a barrel.

“I think oil prices will remain at these levels for the next six to seven months,” Nizar Al Adsani said. The chief executive added, ahead of Opec releasing its monthly report tomorrow, that prices would not increase barring fresh political crises, a change in Opec production policy or until concerns eased over the world’s economic recovery.

Opec’s market update will be followed by the International Energy Agency’s (IEA) report, collectively setting the tone for energy markets in the new year. They are expected to reveal how much the 12-member group is actually producing after it decided to maintain official output levels

at 30 million barrels per day (bpd), around 1 million bpd more than global demand for its oil.

The group pumped 30.56 million bpd in November, exceeding its quota of 30 million for a sixth straight month, according to estimates compiled by Bloomberg. Last month the IEA, in a rare move, predicted a further drop in oil prices.

“While there has been some speculation that the high cost of unconventional oil production might set a new equilibrium for Brent prices in the $80 to $90 range, supply and demand balances suggest that the price route has yet to run its course,” the IEA said.

It added that lower Chinese economic growth and US shale output could result in prices falling further in the upcoming year. “A well supplied oil market in the short term should not disguise the challenges that lie ahead, as the world is set to rely more heavily on a relatively small number of producing countries,” said the IEA chief economist Fatih Birol.

Meanwhile the US shows no signs of cutting back its shale oil production, which has increased by 3.6 million barrels a day over the past four years. Recently released rig count numbers in the US show the first gain in three weeks to a total of 1,575, defying predictions of a drilling slowdown, according to Baker Hughes.

China's Shale Gas Sector To Expand Despite Target Reduction Natural Gas Asia + NewBase




China’s shale gas sector continues to expand despite reduction in medium-term shale gas production, Fitch Ratings said Sunday.

“China's revision of its medium-term shale gas production targets reflects the numerous challenges facing the business despite the country's large shale gas resources. The sector, however, continues to expand with more capital allocated to it and as drilling costs fall, although a fairer allocation of shale blocks is the key to involving more private-sector companies,” Fitch said.

China has cut its 2020 shale gas production targets by more than half to 30 billion cubic metres, reflecting the

difficult geology of its shale basins, higher drilling costs, water scarcity and the limited success domestic operators have had so far with shale blocks allocated in the two rounds since 2011. Production has been low despite numerous benefits - including tax incentives and subsidies - provided to encourage production, Fitch said.

State-owned companies China Petroleum and Chemical Corporation (Sinopec) and Petrochina Company Limited continue to lead production. Gas producers, including Sinopec, were fined by the regulator in November 2014 for failing to meet spending pledges on allocated shale gas blocks, indicating the Chinese government is pushing hard to increase production, said Fitch. Sinopec has had the most success to-date with its Fuling project. According to Fitch, this project has relatively good economics, and has benefitted from rapidly falling drilling costs (although they remain much higher than in the US) driven by the company's experience in this sector and its employment of different technologies.

The Fuling project's success cannot be easily replicated at nearby basins or other more difficult shale basins in China, but Fitch expects the two domestic oil majors to commit to higher shale gas

production.

On 3 December 2014, Petrochina announced it will partner several domestic companies and spend over $4bn on shale gas development projects. In general, Fitch expects most Chinese national oil companies (NOCs) to trim their overall capex, but increase focus on domestic upstream activity to boost oil & gas production.

In the two rounds of shale block allocation to-date, central government-owned operators have generally been given access to shale blocks that overlap with their existing conventional oil & gas acreage.

“It appears that other operators have received more challenging blocks. However, the lack of production from non-NOC operators cannot be solely attributed to this, as inadequate access to technology and to an extent, capital have also been an issue for these operators. China is said to be preparing for a third round of shale block auctions. With greater knowledge of resources and




costs involved, it is likely the state will focus on blocks that have stronger prospects in the next round,” Fitch said.


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Khaled Malallah Al Awadi, Energy Consultant MSc. & BSc. Mechanical Engineering (HON), USA ASME member since 1995 Emarat member since 1990

Mobile : +97150-4822502 [email protected] [email protected]

Khaled Al Awadi is a UAE National with a total of 25 years of experience in the Oil & Gas sector. Currently working as Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has developed great

experiences in the designing & constructing of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Many years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for the local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE and Energy program broadcasted internationally , via GCC leading satellite Channels.

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

NewBase 09 December 2014 K. Al Awadi




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