new base special 01 july 2014

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NewBase 01 July 2014 Khaled Al Awadi

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UAE sets Gulf pace in non-reliance on hydrocarbons

The UAE leads Gulf countries in its attempt to diversify its economy away from hydrocarbons, but the country is still overreliant on the energy sector, say analysts at ratings agency Standard & Poor’s. “The [UAE] economy appears [to be] the most diversified in the GCC,” said the report. But “in our opinion [it] remains dependent on hydrocarbon revenues”. The need to diversify away from energy is a high priority for the country’s rulers, who have used sovereign wealth funds to support new industries.

In Abu Dhabi, Mubadala Development has acted as a key investor to develop non-oil industries, including light manufacturing and aerospace, while the Investment Corporation of Dubai invests in the emirate’s real estate, transport and retail sectors.

The UAE’s rulers have stated their aim to move towards a “knowledge-based economy”, as part of the country’s “Vision 2020” development plan. The Government has sought to build national champions in key industries – most notably Arabtec in the construction sector, and Etihad Airways in aviation.




The report said that the UAE has a “relatively high” fiscal break-even price of US$80 per barrel, meaning that the country will run a deficit if the price of oil falls below this level. This break-even point is higher than Saudi Arabia, Qatar, Oman, Kuwait and Bahrain.

However, the country has 81 years of known hydrocarbon reserves, at its current levels of production, which means that diversification is less urgent than for other Gulf nations. Bahrain and Oman have 11 and 21 years of reserves remaining at current levels.

Only 5 per cent of Dubai’s economy is accounted for by oil and gas, which has encouraged the emirate’s rulers to develop other key industries – largely tourism, real estate, logistics, and aviation – in a bid to keep growth rates high. This has helped to decrease the country’s reliance on hydrocarbon exports by 15 per cent since 2001, as other industries have grown in importance.

S&P’s analysts point out, however, that much of the diversification taking place in the Gulf is in downstream segments of the energy industry – refining, marketing and distribution of energy products. Although technically contributors to an economy’s non-oil sector, downstream industries will still be affected by changes in the demand for oil.

The analysts conclude that diversification away from oil and gas could boost the credit ratings of Opec states, including the UAE.Abu Dhabi earns 65 per cent of its revenues from the oil and gas sector.




GCC dependence on hydrocarbons a credit risk: S&P Written by Oman Observer

Gulf sovereigns’ dependence on hydrocarbon revenues is a key vulnerability of their economies and their ratings, says Standard & Poor’s Ratings Services in a report titled: “Hooked On Hydrocarbons: How Susceptible Are Gulf Sovereigns To Concentration Risk?”

The significant oil and gas reserves and the high income that the oil and gas sector generates, results in general government surpluses, low government financing needs, and net external asset positions for most Gulf Cooperation Council (GCC) countries — Bahrain, Kuwait, Oman, Qatar, Saudi Arabia and the United Arab Emirates (UAE). However, their high concentration on this sector, in which prices and volumes are highly cyclical, is also a credit risk, the report said.

“We view the GCC states’ dependence on the oil and gas sector as a key vulnerability, particularly absent the accumulation of significant financial buffers, should there be a sharp and sustained decline in the oil price or in hydrocarbon export volumes,” said Standard & Poor’s credit analyst Trevor Cullinan. “A sharp and sustained fall in the oil price or in hydrocarbon export volumes would significantly dent their economic and financial indicators.”

On average, hydrocarbon revenues constitute 46 per cent of nominal GDP and three-quarters of total exports of the six GCC countries. Furthermore, this strong dependence on hydrocarbon revenues appears to be increasing. This is partly a result of high oil prices feeding through to the national accounts data, but also because these countries have made only marginal progress in




diversifying their economies away from hydrocarbons. Nevertheless, some GCC countries appear more vulnerable than others to a drop in oil prices, according to Standard & Poor’s analysis of certain economic, external, and fiscal risk indicators.

“We assess Bahrain and Oman as highly vulnerable to a fall in hydrocarbon prices or production. They have the highest fiscal breakeven oil prices among GCC states. Based on 2013 data, for Bahrain the oil price needs to be $18 higher than the current oil price for the sovereign to achieve a balanced budget.Bahrain and Oman also have the least amount of time available before their hydrocarbon revenues would be significantly diminished, absent any further oil and gas discoveries or changes to current production levels, at 11 and 21 years, respectively.

Meanwhile, Qatar and the UAE are the least vulnerable to a sharp drop in oil prices. Although hydrocarbons account for more than half of Qatar’s nominal GDP and 90 per cent of its export revenues, it nevertheless has available 100 years of hydrocarbon production at current levels and a low fiscal breakeven oil price.

The UAE economy, although dependent on hydrocarbon revenues, appears the most diversified in the GCC, with oil and gas contributing only 31 per cent of its total exports, the report added. (OEPPA Business Development Dept) .




Gazprom Neft begins exploratory drilling at the Dolginskoye field in the Arctic. Source: Gazprom Neft

Gazpromneft-Sakhalin, a subsidiary of Gazprom Neft, has started drilling a new exploration well in the Dolginskoye field on the continental shelf in the Pechora sea. The work is being carried out during the ice-free months of 2014 and will involve drilling a single well to a depth of 3,500m and conducting a full range of geological investigations. The experience gained from previous work on the continental shelf, including at the relatively nearby Prirazlomnoye field also operated by Gazprom Neft, was taken into account during preparations for the exploration programme.

Major global service companies such as Schlumberger and Weatherford are involved in the Dolginskoye project. Based on initial studies, a further programme will be drawn up to explore the field and prepare for exploratory drilling during the ice-free seasons in the years to follow.

Drilling and testing of the well will be carried out in 2014 by the GSP Saturn jackup rig, which arrived on site in mid-June and is installed directly on the seabed. The rig is authorised to drill on the continental shelf in the Arctic sea and has been modernised and comprehensively audited by authoritative international and Russian specialist agencies. These have confirmed that GSP Saturn is fully fit for exploratory drilling in the Pechora sea.

Advanced innovative technology will be employed, including environmentally safe water-based drilling fluid system. A rotary control system will be used for drilling on the Arctic shelf, which will speed up drilling and reduce drilling mud. Any mud produced will be shipped back to the mainland to be recycled in line with the zero-discharge policy. In addition, an innovative borehole management system from one of the world’s leading hydrodynamic survey companies will be used for the first time in Russia to improve reliability and quality of work. This technology will speed up the study of the oil reservoir and enable high-quality measurements to be taken with maximum safety and efficiency. This will be the first time that some of this technology has ever been used in Russia.




Drilling and testing of the well will be carried out by the GSP Saturn jackup rig

The Spasatel Karev emergency support vessel will be on hand round the clock while work is taking place. Along with the four ships chartered for ancillary work, it is equipped with a DP-2 dynamic positioning system that allows it to maintain a fixed position for loading in extreme weather conditions. The border checkpoint at Varandey airport has been extended to allow flights to the Dolginskoye field. Until now the airport has only been open for flights to the Prirazlomnoye platform.

GSP Saturn

The GSP Saturn is fully authorised to drill on the Arctic shelf. It has undergone cutting-edge refurbishment in 2009 which included fitting drilling and marine equipment and equipping the platform for operation in northern latitudes under severe wind and wave conditions. The Saturn meets the latest international standards for industrial and environmental safety and has held Dutch and Danish permits to drill on the Arctic shelf since 2009. In 2013 the platform carried out drilling work on a project for German Wintershall in the North Sea.

Dolginskoye oil field

The Dolginskoye oil field lies in the middle of the Pechora Sea, 120km south of the Novaya Zemlya archipelago and 110km north of the mainland. The field was discovered in 1999; the sea is approx. 35-55m deep in the field area. 2D seismic work has been carried out on more than 11,000 linear kms, and 3D seismic on 1,600 linear kms. Three exploration wells have been drilled: two at North Dolginskoye and one at South Dolginskoye. Drilling of another exploration well — North Dolginskoye 3 — began in 2014. Recoverable reserves are currently estimated at over 200 million tonnes of oil equivalent.




UK: Premier Oil sells non-operated interests in Scott, Telford and Rochelle fields to MOL Group . Source: Premier Oil

Premier Oil has sold its non-operated interests in the producing Scott, Telford and Rochelle fields to MOL

Group for a cash consideration of $130 million. MOL will assume the liabilities for future abandonment costs. Year to date production from Scott, Telford and Rochelle has averaged approx. 3.7 kboepd net to Premier.

The transaction, which comprises six UK North Sea licences, has an effective date of 1 January 2014 and is subject to certain pre-emption rights. Completion is subject to receipt of government approval.

Tony Durrant, Chief Executive, commented:

'Our ownership of this package of non-operated assets in the Scott area has generated significant cash flow for the group since acquisition. However, this sale will allow our team in the UK North Sea to focus principally on our operated Solan and Catcher developments, and is a further step towards achieving our targeted disposals for the year.'

Premier's equity in the Scott, Telford and Rochelle fields is 21.8%, 1.6% and 15% respectively. Stellar Energy Advisors acted as an Advisor to Premier Oil for the transaction.




NPD reports high exploration activity in first six months Press Release, June 30, 2014

Exploration activity on the Norwegian shelf remains vigorous. Norwegian Petroleum

Directorate has reported that thirteen new discoveries have been made this year, the

largest of these in the Norwegian Sea.

Eight exploration wells are currently being drilled. As of 24 June, 33 exploration wells have been spudded and 33 terminated. For comparison, the number of exploration wells spudded in the first six months of 2013 was 28. So far this year, 23 wildcat wells and 10 appraisal wells have been drilled. Thirteen new discoveries have been made – seven in the North Sea, three in the Norwegian Sea and three in the Barents Sea.

North Sea

Exploration in the North Sea is down somewhat as a consequence of the final delineation of the Johan Sverdrup discovery. Statoil Petroleum has made six discoveries and Total E&P Norge has made one. The discoveries are all small and close to existing fields.

The southernmost discovery was made east of the Heimdal field in the central part of the North Sea. Here Total has proven oil in wildcat well 25/5-9 in the Heimdal formation in the Palaeocene. Preliminary




estimates place the size of the discovery between 0.5 and 2 million standard cubic metres (Sm3) of recoverable oil.

Statoil proved oil in well 30/11-9 A in the southwestern part of the Oseberg area. The well was drilled as a sidetrack from well 30/11-9 S, which was terminated in 2013. Oil was proven in the Heather formation in the Upper Jurassic and in the Brent group in the Middle Jurassic. In total, the two wells – 30 /11-9 4 S and A – have proven between 3 and 7 million Sm3 of recoverable o.e. (oil equivalents).

Near the Fram field in the northeastern part of the North Sea, Statoil discovered oil in well 35/11-17 in the Fensfjord formation in the Upper Jurassic and in the Brent group in the Middle Jurassic. Preliminary estimates indicate that this discovery is between 1 and 3 million Sm3 recoverable o.e.

The greatest exploration activity has been in the Gullfaks area in the northern part of the North Sea, where Statoil has made four discoveries in Jurassic reservoir rocks. Oil and gas were proven in wells 34/10-54 S and A, the latter drilled as a sidetrack. Preliminary estimates of the size of the two discoveries indicate a total of between 3 and 12 million Sm3 recoverable o.e.

Petroleum has been proven in well 34/10-C-18 A between the Gullfaks and Visund fields. Preliminary estimates place the size of this discovery between 0.2 and 1 million Sm3 recoverable o.e. Well 34/8-17 S, drilled just east of the Visund field, proved oil and gas. The size of the discovery is estimated at between 0.5 and 2 million Sm3 recoverable o.e.

Norwegian Sea

Three discoveries have been made in the Norwegian Sea in the first half of this year. Southwest of the Njord field, VNG Norge AS proved oil and gas in well 6406/12-3 S (Pil) in the Rogn and Melke formations in the Upper Jurassic. A 226-metre hydrocarbon column was proven, of which 135 metres are oil in a reservoir with good flow properties.

The preliminary size estimate for the discovery is between 6 and 21 million Sm3 of recoverable oil and between 2 and 6 billion Sm3 recoverable gas. This is the largest discovery made on the Norwegian shelf so far this year.

Further north in the Åsgard area, gas/condensate was proven in well 6407/1-7 in the Lange formation in the Lower Cretaceous. Preliminary estimates indicate that the discovery contains between 1 and 4 million Sm3 of recoverable o.e.

Further north, just south of the Heidrun field, Faroe Petroleum Norge has made a minor oil and gas discovery in well 6507/10-2 S in the Garn formation in the Middle Jurassic. The preliminary estimate is that this discovery contains between 1 and 2.5 million Sm3 of recoverable o.e.




Barents Sea

Three discoveries have been made in the Barents Sea. Northwest of the Johan Castberg discovery, Statoil found gas in well 7220/4-1 in the Stø and Nordmela formations in the Jurassic, and deeper in the Snadd formation in the Triassic. Preliminary estimates place the size of the discovery between 2 and 4 million Sm3 recoverable gas. Further south in the same area in well 7220/7-3, Statoil discovered gas in the Stø

formation and oil deeper in the Stø and Nordmela formations. Preliminary estimates indicate that this discovery is between 7 and 10 million Sm3 of recoverable o.e. Northeast of the Snøhvit area, Det norske oljeselskap proved a small volume of oil in well 7222/11-2. The discovery was made in the Kobbe formation in the Triassic.

Eight exploration wells are currently being

drilled on the Norwegian shelf – four wildcat wells and four appraisal wells. Some of these will soon be completed, one of which is well 6406/12-3 A, operated by VNG. This well is being drilled on the Bue prospect near well 6406/12-3 S, where VNG recently proved gas and oil in the Pil prospect southwest of the Njord field in the Norwegian Sea.

In the Barents Sea, three wells are nearing completion. Well 7324/7-2, operated by OMV Norge, is being drilled near the 7324/8-1 discovery, (Wisting Central), which OMV proved in 2013. Both well 7324/7-2 and the Statoil-operated well 7325/1-1 are being drilled in the Hoop area in the northern Barents Sea.

Appraisal well 7120/1-4 S is also nearing completion. This well is being drilled by Lundin Norway on the 7120/1-3 (Gohta) discovery north of the Snøhvit area. This discovery was proven in 2013.

Robust exploration activity is expected to continue for the

remainder of the year, with exploration wells planned in the North Sea, Norwegian Sea and Barents Sea. No plans for development and operation (PDOs) have been submitted for discoveries on the Norwegian shelf in the first half of 2014.

The Norwegian Petroleum Directorate (NPD) has granted

Statoil Petroleum AS a drilling permit for well 7325/1-1, in

the Barents Sea.




San Leon Energy announces final results - updates operations Source: San Leon Energy

San Leon Energy, the AIM listed company focused on oil and gas exploration in Europe and North Africa, has announced its audited final results for the year ended 31 December 2013.

Highlights:

Operational

• Poland remains the company's core focus as the Company continues to make good progress in building a

balanced portfolio offering both high impact exploration and near-term production

• Lewino-1G2 frac, Gdansk W Concession in Poland's northern Baltic Basin, produced results which we believe

show the well to be the best single shale frac by any company in Europe to date

• Three hydraulic fracture treatments performed on the Rogity-1 well, Braniewo S licence, Poland. Positive

results are currently being evaluated with a view to selecting the next well location

• Received 100% interest back from Talisman on several Baltic Basin shale concessions

• Continued deal-making with proposed farm-outs and sales announcements to major partners:

o Braniewo S in Poland to Wisent

o Cybinka-Torzym in Poland to Aspect Energy

o Sale of entire Irish asset base, excluding San Leon's NPI in Barryroe, to Ardilaun Energy

• Award of the 36km2 Timahdit oil shale block in Morocco, recent analysis by Enefit Outotec Technology

confirmed commercial potential

• Two year licence extension, to 31 July 2015, on the Durresi Block, offshore Albania

Corporate

• At the start of 2013 Aurelian Oil & Gas, the fourth acquisition in four years, was integrated into the Company

leveraging its assets, business and established technical team

• Appointment of Joel Price as Chief Operating Officer

• Piotr Rozwadowski, a former Vice Minister of State for the Treasury in Poland and responsible for Energy

and Telecoms, appointed Non-Executive Director

Financial

• Loss after income tax and depreciation and for the year of €17.05m mostly due to asset impairment (2012:

profit of €0.46m)

• Net assets increased by €74.3m to €284.4m at 31 December 2013

• Successfully raised £31 million in September 2013 in a placing to fund future operations and the Turkey

acquisition (subsequently amended after the reporting date)

• Major capital expenditure items included three fracs and well testing / clean up of the Lewino-1G2well, and

expenditure in excess of the carry cap on the Foum Draa well (offshore Morocco)

• At year end the group had cash of €11.4m which together with trade receivables of €13.2m which included

monies held in escrow for Turkey and vat recoverable combined with existing and future carried exploration

costs ensures that the company has adequate funding

• Since the end of the reporting period, 2014 has seen a significant uptick in farm in interest, success in which

would be expected to deliver additional cash

Outlook




• Vital read-across in the coming months from BNK and 3Legs/ConocoPhillips multi-fracced horizontal wells

results. The Company's Lewino-1G2 horizontal well is in advanced engineering, and will benefit from the

results of the other operators' wells

• Final well to be drilled on the Rogity-1 well on the Braniewo S licence, Poland, to complete work programme

as part of farm-out agreement with Wisent O&G

• Drilling of Sidi Moussa, offshore Morocco, by Genel Energy scheduled for H2 2014

Oisin Fanning, Executive Chairman of San Leon, said:

'As a whole, 2013 has been a challenging year, not only for San Leon but for many small exploration and production companies. Nevertheless, despite tough market conditions San Leon has made considerable progress - we became the largest shale gas player in Europe by acreage, complemented by a sizeable conventional and tight gas portfolio, and the Company is now poised to move from exploration to production.

Our operational activity in 2013 was dominated by the highly encouraging Lewino-1G2 frac in the Baltic Basin of Poland. Resource play stimulation work in the Main Dolomite and tight Rotliegendes fields was also a priority for the Company, as well as the existing Rogity-1 well on the Braniewo S licence which had three hydraulic fracture treatments performed.

The proposed acquisition of a majority stake in Alpay Enerji ("Alpay"), announced in September 2013, was aimed at cash generation from its assets. Following the completion of due diligence, and as a result of adverse currency shifts and well performance in the interim period, together with the failure to receive Turkish Government approval for the deal by the long stop date, the Board announced in early April 2014 that it had decided not to complete this deal in its proposed form. The material decline in the desirability of the deal, together with the LoIs signed on near-term production assets in Poland (a source of cash flow) and the success of the Lewino-1G2 shale frac, meant that the funds originally earmarked for Turkey would be better spent elsewhere. The original commitment to spend $6.5m by 31st March 2014 on Alpay assets was subject to completion of the deal, and so was not spent. The $4.5m deposit held in escrow was returned to the Company during April 2014.

The future of shale gas development in Poland is set to attract a lot of attention in 2014, with both BNK and 3Legs/ConocoPhillips announcing the results of their multi-fracced horizontal wells. There also appears to be a broader acceptance of shale gas in the EU, as demonstrated by recent developments in Germany and Spain, and we look forward to being a significant part of the future of Europe's unconventional gas industry.'




Malaysia: RH Petrogas commences 2D seismic acquisition in

Block SK331 onshore Sarawak. Source: RH Petrogas

RH Petrogas subsidiary RHP (Mukah) has commenced the acquisition of approx. 550 line kms of 2D seismic survey in Block SK331 onshore Sarawak. The survey is expected to be completed in November 2014.

Block SK331 is a large block covering an area of 11,600 sq kms. The design and layout of the 2D seismic survey is based on the results of the 12,414 line kms of full tensor gradiometry ('FTG') survey conducted in 2013 and of the reprocessing of old seismic lines within the block. Through the results of this new 2D seismic survey, the Company is targeting to further evaluate several identified leads in order to upgrade and mature one or more of them into prospective candidate(s) for exploration drilling.

RHP (Mukah) is the operator of Block SK331 and holds an 80% working interest in the block. Its partner is Petronas Carigali which has a 20% working interest and is owned by Petroliam Nasional Berhad, the national oil company of Malaysia which is vested with the entire ownership and control of the petroleum resources in the country.




Thailand: Mubadala's Rojana-1 exploration well in Gulf of

Thailand block G11/48 disappoints . Source: KrisEnergy

JV partner KrisEnergy has announced that drilling operations have concluded at the

Mubadala-operated Rojana-1 exploration commitment well in block G11/48 in the Gulf of

Thailand. Rojana-1, which commenced drilling on 23 June 2014, reached a total depth at

4,916 feet (1,498.4 metres) measured depth, or -4,126 feet total vertical depth subsea. No

significant hydrocarbon shows were detected in the target reservoirs.

Water depth at the well location is 230 feet. The well is the final commitment well for the G11/48 licence, where the joint-venture partners are developing the Nong Yao oil field. Nong Yao is expected to commence oil production in the first half of 2015. G11/48 covers 3,374 sq km over the southern margin of the Pattani Basin and the northwest margin of the Malay Basin in water depths of up to 75 metres. The block also contains the Angun and Mantana

oil and/or gas discoveries.

KrisEnergy holds 22.5% working interest in G11/48. Mubadala Petroleum G11 (Thailand), the operator, has a 67.5% working interest and Palang Sophon holds 10%. Rojana-A was drilled using the Atwood Orca jack-up rig owned by Atwood Oceanics.




Thailand: KrisEnergy gives go-ahead for Wassana oil development. Source: KrisEnergy

KrisEnergy has announced that it has approved the final investment decision for the development of the Wassana oil field in the Gulf of Thailand G10/48 licence where production is anticipated to commence in the second half of 2015. The Company has secured a mobile offshore production unit ('MOPU') for a fast-

track, flexible development concept.

The Wassana development concept comprises a MOPU and 12-14 development wells producing to a floating storage offloading vessel. The Company has secured the use of a converted Bethlehem Matt Type jack-up rig currently employed as a MOPU offshore Malaysia. The unit is suitable for water depths up to 65 metres and has full hydrocarbon processing facility for up to 20,000 barrels of oil per day ('bopd') and a water injection capacity of 15,000 barrels per day. KrisEnergy will take delivery of the MOPU in September 2014 when it will go into drydock for inspection and minor refurbishments.

KrisEnergy holds 100% working interest in G10/48, which covers 4,696 sq km over the southern section of the Pattani Basin in water depths up to 60 metres. The licence contains three oil discoveries - Wassana,

Niramai and Mayura - in various stages of development or appraisal. The Wassana oil field is expected to reach a peak production of 10,000 bopd.

Chris Gibson-Robinson, Director Exploration & Production, commented: 'Having taken over operatorship of G10/48 in mid-May we are making good headway in advancing the Wassana development. The MOPU solution is efficient both in timing and costs, but also provides the flexibility to look at future commercialisation of other discoveries in the G10/48 licence area. We have also mapped a portfolio of prospects and leads in this block, some of which will provide additional development areas once we have completed further exploration drilling.'




Oando: ConocoPhillips transaction to close on July 31 Source : Oando

Oando Energy Resources Inc. and ConocoPhillips have entered into an agreement to

extend the outside date for completion of the proposed acquisition of the Nigerian

Upstream Oil and Gas Business of ConocoPhillips to July 31, 2014.

The parties extended the outside closing date for completion of the ConocoPhillips Acquisition to

enable them finalise activities required to complete the transaction

having received the required consent of the Honourable Minister of Petroleum Resources in Nigeria. The value of the transaction is estimated at $1.65 billion.




ONGC approves Mumbai High redevelopment proposal Source: ONGC

The Board of India’s oil and gas company ONGC approved the proposal for Redevelopment of its giant offshore field – Mumbai High (North), located some 162 kilometres off the coast of Mumbai, India.

The redevelopment will involve a capital investment of Rs 5,706.47 Crore (around USD 950 million) including Foreign Exchange component of Rs 4,421.76 Crore (USD 743.15 Million at exchange rate of Rs. 59.50/USD).

The implementation of the project will lead to incremental gain of 6.997 million tonne (MMT) crude oil and 5.253 billion cubic metres (BCM) gas by 2030. This project is designed to carry forward the success of the previous two editions of redevelopment projects and give a new lease of life to the giant field which is so vital for the economy of the country.

The total CAPEX includes creation of surface facilities for Rs 2,586.42 Crore, new oil and gas wells for Rs 1,992.11 Crore and sidetracking of existing wells for Rs 1,127.94 Crore.

The facilities envisaged under the project are Installation of 5 well platforms, one clamp-on facility for wells at an existing platform, associated pipelines and modifications at 13 platforms, drilling of 52 new wells and 24 sidetrack wells. The facility parts under the project are scheduled to be installed by April, 2016, while drilling of wells and the overall project completion is scheduled for May 2017.

The strategy of Mumbai High North Re-Development (MHNRD Phase-III) scheme includes opportunities for further development of LI, LII, S1 and other minor reservoirs along with the major LIII reservoir and integrating the required inputs.




Scotland May Have Shale For 30 Years' Worth Of UK Gas Needs by Reuters

|Scotland, heading for a September independence referendum, could hold enough shale gas resources to cover UK gas needs for more than 30 years, a geological report published by the British government showed on Monday.

But Scotland's roughly 80 trillion cubic metres of gas is only around 6 percent of Britain's potential, with the rest mainly in the Bowland Shale region across northern England. The British Geological Survey report, the third focusing on high potential areas which have covered northern and southern England, said the populous Midland Valley area of Scotland also holds around 6 billion barrels of shale oil.

Energy Minister Michael Fallon set the findings firmly in the context of Scotland potentially splitting from Britain. "Only the broad shoulders of the United Kingdom can attract investment in new energy sources and maintain the UK's position as one of the world's great energy hubs -generating energy and generating jobs," he said in a statement

Britain is betting on the development of shale gas to help curb its growing dependence on imports and to stem a decline in oil and gas tax receipts as output from the mature North Sea basin falls rapidly. Scotland already produces the bulk of Britain's oil and gas and estimates for future conventional fossil fuel production show this is set to continue. In total, the three BGS reports on unconventional oil and gas resources showed Britain has around 1,409 trillion cubic feet of shale gas

and 10.4 billion tonnes of shale oil in place. These estimates are based on scarce data and further exploratory drilling needs to be undertaken to determine how much shale oil and gas can actually be recovered, the BGS said.

None of Britain's shale gas explorers have yet undertaken any hydraulic fracturing, or fracking, whereby shale gas is extracted from deep rock formations by breaking it using water, sand and chemicals.The shale gas industry is gearing up for Britain's first onshore oil and gas licensing round in six years that will allow companies to bid for permits in shale oil and gas areas.

Some of the companies active in Britain's shale market are IGas, Egdon Resources and Cuadrilla."This report will give reassurance to investors who wish to explore for oil and gas onshore in Scotland," said Ken Cronin, chief executive of the UK Onshore Operators Group representing the industry.

Some critics of shale gas, including environmental groups, claim shale gas extraction damages the environment because of harmful chemicals it uses.




2014 U.S. petroleum refinery update: capacity edges up, ownership shifts Source: U.S. Energy Information Administration, Refinery Capacity Report

As of January 1, 2014, there were 139 operating refineries and three idle refineries with total atmospheric crude oil distillation capacity (ACDU) of 17.9 million barrels per calendar day (bbl/cd), a 101,000-bbl/cd increase in capacity from January 1, 2013. In 2013, four refineries changed ownership, continuing the trend of a handful of sales each year. This information is detailed in EIA's recently released Refinery Capacity

Report, which surveys U.S. refinery ownership and capacity annually at the start of each year.

What is calendar day capacity?

Barrels per calendar day is a measure of the amount of input that a distillation unit can process in a 24-hour period

under usual operating conditions. It takes into account both planned and unplanned maintenance.

Valero Energy Corporation remains the largest U.S. refiner, with total ACDU capacity of more than 1.9 million bbl/cd. Exxon Mobil Corporation is second at almost 1.9 million bbl/cd. With the purchase of the Texas City refinery from BP, Marathon Petroleum Corporation became the third-largest refiner, with a capacity of 1.7 million bbl/cd. Marathon is calling the refinery Galveston Bay to distinguish it from the much smaller Texas City refinery Marathon had already owned. Phillips 66 fell to fourth-largest and Motiva remained fifth-largest. Combined, these five companies own 45% of total U.S. refining capacity. With its purchase of the Carson refinery, Tesoro became the largest refiner on the West Coast. The concentration of refinery ownership in other regions is mostly unchanged from last year. PBF Energy Corp and Marathon Petroleum still lead the East Coast and Midwest in refining capacity, respectively. Valero has the most capacity in the Gulf Coast region, and Suncor has the most capacity in the Rocky Mountains.




In 2013, Nustar Refining sold its San Antonio, Texas, refinery (16,112 bbl/cd) to Calumet Specialty Products Partners. BP sold two refineries in 2013, one in Texas City, Texas (451,000 bbl/cd), to Marathon Petroleum Corporation, and a second in Carson, California (251,000 bbl/cd), to Tesoro Corporation. Tesoro sold its Ewa Beach (Kapolei), Hawaii, refinery (93,500 bbl/cd) to Par Petroleum Corp.




900Km off-shore Gas Pipeline installation begins at Ichthys project Press Release, June 30, 2014

Japan’s INPEX today announced that gas export pipeline installation works began at

its Ichthys LNG Project on June 28, following the earlier arrival of the Saipem-operated,

semi-submersible pipelay barge SEMAC-1 in the Northern Territory.

The Project’s 889 kilometre Gas Export Pipeline will connect the onshore processing facilities near Darwin to the Ichthys gas-condensate field in the Browse Basin, offshore Western Australia.

Managing Director of Ichthys LNG Project Louis Bon said that the SEMAC-1 had officially started the 164 kilometre shallow water pipelay component of the gas export pipeline installation, which includes laying the first 18 kilometre section of 42-inch diameter pipe through Darwin Harbour.

“The gas export pipeline will deliver gas and some condensate from our offshore central processing facility

to the Ichthys LNG Project onshore facilities at Bladin Point near Darwin so that it can be processed for

export,” Bon said. “The commencement of the pipelay work means we are starting to physically connect our

home base in Darwin to the Ichthys gas-condensate field where our semi-submersible offshore facilities will

be permanently moored for the life of the Project.

Working from east to west in Darwin Harbour, the SEMAC-1 will first feed pipe to the Project’s landfall site for a three kilometre shore-pull. This work supports the onshore component of the GEP, which will stretch about seven kilometres from the beach valve at Middle Arm to the Bladin Point onshore processing facilities. The SEMAC-1 is scheduled to be in Darwin Harbour for about four weeks. In total, the 164 kilometre shallow water pipelay installation is scheduled to take about 80 days. Once completed, the SEMAC-1 will transfer work to Saipem’s deep water installation vessel, Castorone, which will lay the remaining 718 kilometres of pipe to the Ichthys gas-condensate field.




International oil and gas contracting service provider Saipem is the engineering, procurement, construction and installation (EPCI) contractor for the Ichthys LNG Project’s GEP and has extensive experience on similar large diameter pipeline projects around the world.




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

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Khaled Al Awadi is a UAE National with a total of 24 yearsKhaled Al Awadi is a UAE National with a total of 24 yearsKhaled Al Awadi is a UAE National with a total of 24 yearsKhaled Al Awadi is a UAE National with a total of 24 years of experience in theof experience in theof experience in theof experience in the Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as

Technical Affairs Specialist fTechnical Affairs Specialist fTechnical Affairs Specialist fTechnical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for or Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for or Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for or 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 the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations 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 Manager in Emarat , responsible for Manager in Emarat , responsible for Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has developed Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has developed Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has developed Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has developed

great experiences in the designing & constructinggreat experiences in the designing & constructinggreat experiences in the designing & constructinggreat experiences in the designing & constructing of gas pipelines, gas metering & regulating stations and in the engineering of supply of gas pipelines, gas metering & regulating stations and in the engineering of supply of gas pipelines, gas metering & regulating stations and in the engineering of supply of gas pipelines, gas metering & regulating stations and in the engineering of supply

routes. Many yearoutes. Many yearoutes. Many yearoutes. Many years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for rs were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for rs were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for rs 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 andthe local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andthe local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andthe local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE and Energy program broadcasted Energy program broadcasted Energy program broadcasted Energy program broadcasted

iiiinternationally , via GCC leading satellitenternationally , via GCC leading satellitenternationally , via GCC leading satellitenternationally , via GCC leading satellite ChannelsChannelsChannelsChannels . . . .

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