The Azerbaijan International Operating Company (AIOC), operated by BP, announced on Wednesday the start-up of oil production from the West Chirag platform as part of the Azeri-Chirag-Gunashli (ACG) field development in the Azerbaijan sector of the Caspian Sea. Start-up of the West Chirag platform completes the Chirag Oil Project (COP) sanctioned in 2010.
West Chirag production began from one of the pre-drilled wells - J05, on 28 January. The oil will first pass through the newly installed processing facilities on the platform and then will be exported to the Sangachal Terminal via a new in-field pipeline linked to an existing 30" subsea export pipeline. Production will increase through 2014 as the other pre-drilled wells are brought on line.

Gordon Birrell, BP's Regional President for Azerbaijan, Georgia and Turkey, said: "The start-up of COP marks a major milestone in the development of the super- giant ACG field. West Chirag is the eighth world-class offshore platform that we have built and operated in a safe and efficient manner in the Caspian. To date the ACG field has produced over 2.3 billion barrels of oil and with future continual major investments in new technologies and facilities, like the one we have today started up, it will continue to produce as a world-class reservoir for many decades. BP as the operator of the ACG field and our partners are committed to continuing the efforts that are expected to take us step by step towards optimization of production and maximization of the field recovery. We believe COP represents a big step forward towards stabilizing ACG's production and increasing recovery by drilling more wells from the new West Chirag facility.

"I would like to take this opportunity to thank the thousands of people, mostly from Azerbaijan, who built and installed the subsea pipelines, jacket and topsides unit of the new platform, for their dedication and outstanding performance over the past four years. I would also like to congratulate the government, our partners, employees, all the contractors, suppliers, and everyone else involved on this tremendous achievement. I would like to specifically highlight the outstanding performance of ACG's project, drilling, and operations teams in safely achieving First Oil. This demonstrates our ability to continue the impressive track record of planning, construction, and operations delivery in the Caspian Sea".
The West Chirag platform has been installed at a water depth of about 170 metres between the existing Chirag and Deepwater Gunashli platforms. The design oil capacity of the new platform is 183 thousand barrels per day. The gas export capacity is 285 million standard cubic feet per day.

CG participating interests are: BP (operator – 35.8%), SOCAR (11.6%), Chevron (11.3%), INPEX (11%), Statoil (8.6%), ExxonMobil (8%), TPAO (6.8%), ITOCHU (4.3%), ONGC Videsh Limited (OVL) (2.7%).

Royal Dutch Shell plc ("Shell") has announced it has agreed to sell its 8% equity interest in the Wheatstone-Iago Joint Venture and 6.4% interest in the 8.9 million tonnes per annum Wheatstone liquefied natural gas (LNG) project in Western Australia for a cash consideration of US$1,135 million to the Kuwait Foreign Petroleum Exploration Company (KUFPEC), subject to closing.

Royal Dutch Shell plc ("Shell") today announced it has agreed to sell its 8% equity interest in the Wheatstone-Iago Joint Venture and 6.4% interest in the 8.9 million tonnes per annum Wheatstone liquefied natural gas (LNG) project in Western Australia for a cash consideration of US$1,135 million to the Kuwait Foreign Petroleum Exploration Company (KUFPEC), subject to closing.

Shell Chief Executive Officer Ben van Beurden commented: "Shell will remain a major player in Australia's energy industry. However, we are refocusing our investment to where we can add the most value with Shell's capital and technology. We are making hard choices in our world-wide portfolio to improve Shell's capital efficiency."

The agreement with KUFPEC, an existing Wheatstone joint-venture partner, ensures there will be no impact on existing commercial agreements.

US $ 24 M for the supply of special DHT cable systems for O&G extraction application

This new assignment follows the award as Petrobras "Best Supplier" recently received.

Prysmian Group, world leader in the energy and telecom cables and systems industry, has been awarded a new contract worth approximately US $ 24 million, by the Brazilian oil company Petrobras.

Photo: Prysmian Group's technology and products lie at the core of major worldwide development projects in the OG&P industry

The award refers to special Down Hole Technology (DHT) systems for offshore oil and gas extraction application to be delivered in July 2014, that will be manufactured in the Group's facilities in Bridgewater, NJ (USA) and Cariacica, Brazil, using materials (namely steel) of Brazilian sourcing. DHT systems are technology-driven specialty products for oil, gas and geothermal wells that include Tubing Encapsulated Cables used in individual wells to monitor temperature, pressure, and other parameters to better control flow though overall reservoirs.

Recently the Group has received the annual Petrobras award for Best Supplier of Goods and Services in the Campos Basin (category Goods, section Large Supplies). The award has the target of paying a tribute to Companies that show the best quality levels in the supply of goods and services to Petrobras units in the Region. Competitiveness and performance (including safety and on-time delivery) were among the many criteria for the selection of winners. Other prestigious names in the contest were Halliburton (ranking second in the same category won by Prysmian), FMC Technologies and Ernst & Young.

Prysmian has a long-standing tradition of more than 35 years of technical and commercial partnerships with Petrobras, with Technical Cooperation Agreements and supplies of flexible pipes and umbilicals - both Steel Tube and Thermoplastic- for several projects. In recent times the Group has also been awarded by Petrobras a new major contract related to a frame agreement for Umbilical products for offshore oil and gas extraction worth approximately $ 260 Million (with 50% minimum purchasing commitment and call-off orders to be placed within a two-year period) and the extension to 2016 of the existing frame agreement for flexible pipes, worth a total of $ 95 Million ($ 20 Million have already been called off for the Macabu, Jubarte and Marlim Leste fields).

Within its worldwide industrial footprint, Prysmian Group can rely on 5 production facilities dedicated to SURF (Subsea Umbilicals, Risers and Flowlines ) products: 3 in the Espirito Santo State in Brazil (2 in Vila Velha, for Umbilicals - both Steel Tube and Thermoplastic- and flexible pipes, and 1 in Cariacica, for both SURF products and DHT systems) and 2 in North America (Bridgewater, New Jersey and North Dighton, Massachusetts for DHT systems), a presence that over the past years has allowed Prysmian to diversify and further expanding its activities in the market of technology and products for the OG&P industry.

The Bureau of Safety and Environmental Enforcement (BSEE) have announced that it is soliciting proposals for oil spill response research projects and will be investing up to $7 million to support these projects in 2014. In a Broad Agency Announcement released on the federal governments business opportunities website, www.FedBizOpps.gov, the bureau called for white papers focusing specifically on one of 10 topic areas for proposed research covering oil spill response operations on the U.S. Outer Continental Shelf.

"This announcement continues and enhances BSEE's commitment to a comprehensive research program dedicated to improving oil spill response operations," said BSEE Oil Spill Response Division Chief David Moore. "Through efforts such as this, we hope to spur further innovation and to improve upon the techniques and technology available to respond to potential oil spills."

The deadline for submitting white papers is January 20, 2014. Topics should be limited to the following:

- cataloging BSEE's oil spill response research programs funded research recommendations and key findings that may have an Impact on BSEE regulations;

- scientifically based planning standards for dispersant effectiveness and usage rates;

- scientifically based planning standards for burn boom effectiveness and usage rates;

- oil spill detection and analysis using remote sensing technologies;

- subsea oil spill detection sensors;

- mechanical recovery capability of chemically treated oil;

- solidifying the scientific capabilities of Ohmsett - quantifying mixing energy;

- solidifying the scientific capabilities of Ohmsett - effect of ambient chemical levels;

- development of "smart" skimming technologies; and

- establishment of technology readiness level definitions for oil spill response equipment.

For more information on these topics and directions for submital, please view the announcement here at www.FedBizOpps.gov.

Angola LNG has announced the sale of its first LPG cargo from its plant in Soyo, the facility built to create value from Angola's offshore gas resources.
The first cargo was sold to Sonangol, Angola's state oil & gas company, on a Free on Board (FOB) Soyo basis and shipped by the LPG carrier BW Broker. All LPG and condensate products have been committed for sale to the shareholder affiliates of Angola LNG.

The LPG and condensate jetty was commissioned immediately prior to commencement of loading operations. Commissioning included the testing of safety devices, mooring arrangements and loading arms.

Commenting on the first cargo Artur Pereira, CEO, Angola LNG Marketing, said: "In addition to LNG production for international markets propane, butane and condensate production at Angola LNG is an important part of our operational and commercial activity. Our LPG and condensate production will help to supply both domestic and export markets with their energy needs."

In addition to its LNG facilities Angola LNG's liquids infrastructure at its production plant in Soyo includes storage tanks for 88,000 m3 of propane, 59,000 m3 of butane, and 108,000 m3 of condensate. It has a jetty dedicated to propane, butane and condensate loading and a second jetty for pressurised butane loadings which will serve the domestic market.

Today's announcement marks a further milestone in the continued development of Angola's oil and gas resources and provides a new source of energy for Angola and export markets.

Angola LNG Limited is an incorporated joint venture between Sonangol, Chevron, BP, ENI and Total that will gather and process gas to produce and deliver LNG and NGLs. The plant has an expected life of at least 30 years.

Angola LNG will gather, process, sell and deliver 5.2 million tons per year of LNG - plus natural gas, propane, butane and condensate - from its plant in Soyo, Angola; one of the world's most modern LNG processing facilities. Angola is the second-largest oil producer in sub-Saharan Africa. Historically associated gas has been flared or re-injected into the reservoirs, but Angola LNG provides a solution to reduce emissions and establish a new source of clean energy.

Shareholders of Angola LNG Limited are Sonangol (22.8%), Chevron (36.4%), BP (13.6%), ENI (13.6%), and Total (13.6%).

At $10bn the Angola LNG infrastructure is one of the largest ever single investments in the Angolan oil and gas industry. Offering a dedicated fleet of seven LNG vessels and three loading jetties (LNG, liquids and compressed butane) Angola LNG's mission is to contribute to the elimination of gas

Statoil has been awarded interests in 10 production licenses in the Awards in Predefined Areas 2013 (APA 2013) on the Norwegian continental shelf. Statoil will be the operator in seven of the licenses.

Statoil has been awarded new acreage in all three NCS provinces - the Barents, Norwegian and North seas. (Photo: Harald Pettersen)

"We are very pleased with the APA 2013 award, which is in line with our strategy. It makes a good basis for further developing the NCS as a core area for Statoil," says Irene Rummelhoff, newly appointed senior vice president for NCS exploration in Statoil.

"The mature areas of the NCS are very attractive. Familiar geology contributes to high discovery rates, while well-developed infrastructure yields high-value barrels," says Rummelhoff.

Statoil has been awarded new acreage in all three NCS provinces:
Barents Sea

40% ownership and operatorship in PL765 - a new license in the Hammerfest basin. We see exciting potential in the area, particularly in some of the more under-explored plays.

Norwegian Sea

40% ownership and operatorship in PL755. This is an interesting area east of Heidrun awarded to secure optimal near-field exploration.

60% ownership and operatorship in PL752 and 20% ownership in PL751 - two new licenses in the less mature Frøya high/Froan basin where we are taking a fresh perspective on traditional and new plays.

North Sea
30% ownership and operatorship in PL745S south of the Valemon field in the Tampen area. Here we will work on near-field exploration opportunities.
50% ownership and operatorship in PL739S. This is an exciting award in a large underexplored area southeast of Oseberg
50% ownership and operatorship in PL072D east of Sleipner to secure a near-field exploration opportunity in a mature area of the North Sea.
20% ownership in PL735S in the central Viking Graben. Here we see an interesting concept along the north-western flank of the Utsira High.
77.8% ownership and operatorship in PL333B. This is additional acreage in the King Lear area.
30% ownership in PL044B - additional acreage in the vicinity of PL044 in the southern North Sea.

Statoil believes that the mature areas of the NCS still offer exciting exploration opportunities. The company is taking targeted steps in order to unlock the full potential of the mature areas, thus maximizing value creation on the NCS.

"In 2012 we established three growth projects within our Exploration Norway team covering the most interesting parts of the Norwegian and North seas. The aim of the growth projects is to leverage our regional knowledge and come up with new creative ideas and exploration concepts. Our APA 2013 application was to a large extent based on the opportunities matured by the growth projects," says Rummelhoff.

Rummelhoff emphasizes that access to new quality acreage is essential for maintaining the NCS production level beyond 2020.
Earlier this month Statoil delivered to the authorities its nomination of blocks for the 23rd licensing round.

Demonstrating how GE technology helps operators extend the life of aging offshore production equipment, GE Oil & Gas (NYSE: GE) is supplying Statoil Petroleum AS (OSE: STL, NYSE: STO) with its fifth generation SemStar5 Subsea Electronics Module to upgrade and extend the life of the subsea production control system for the Troll B field.
GE Oil & Gas designed, built and installed the original Troll B subsea production system in 1995. The new Troll B subsea control system will upgrade all wells on manifolds D, E, F, G and H.

The award-winning SemStar5 will be designed to be backwards compatible with the existing system and will replace the reliable, but now obsolete technology that was provided originally. The SemStar5 offers architectural flexibility for a variety of production control system applications, and has successfully been deployed on several Statoil fields in recent years and has been field proven as a robust and reliable solution for upgrading subsea production control systems.

Featuring a modular design approach, SemStar5 is an example of the Industrial Internet's role in boosting equipment efficiency and performance by providing the infrastructure that supports the higher bandwidth requirements of modern instrumentation while also offering high reliability. The modular design draws on GE's nearly 30 years of experience with subsea systems.

The first application of the new technology was for Statoil's Tordis Vigdis Controls Modification project in the North Sea, west of Norway, in about 656 feet (200 meters) of water.

Troll B was originally installed with a 20-year field life. Two decades later, GE is successfully maintaining the system on behalf of Statoil through its obsolescence management and active brownfield offerings.

"GE's subsea production control system upgrade for Statoil underscores the important role that advanced and ultra-reliable controls technology can play in supporting new and existing offshore production projects," said Tom Huuse, regional leader—Subsea Systems Services, Nordic Region for GE Oil & Gas. "GE's Subsea Controls and Services team worked closely with Statoil for more than a year to offer its expertise and support Statoil in identifying the optimum, cost-effective solution that minimizes production downtime and provides an expandable controls solution for the future."

In recent years operators have recognized the increased oil recovery opportunities in older fields by targeted technology insertion, and GE has responded to this need with an integrated support suite of offerings based on its leading edge technologies being installed in new green fields. Deployment of common modules and units such as the SemStar5 assure supportability and improved reliability and availability through the extended life of the field. This approach has been successfully validated on a number of projects already, and positions GE to be the brownfield controls supplier of choice for both GE and others' legacy fields.

GE's equipment is scheduled to be delivered in first half of 2015.

The Troll B agreement also marks the latest of several equipment supply orders announced between the two companies in 2013.
Based in Stavanger, Norway, Statoil Petroleum AS explores, produces and transports oil and gas including petroleum and petroleum-derived products. Statoil Petroleum AS is a subsidiary of Statoil ASA.

The Troll field is in the northern part of the Norwegian North Sea, around 65 kilometres west of Kollsnes, near Bergen. The license is operated by Statoil, (30.58 percent) and partners include Petoro (56 percent); Norske Shell (8.10 percent); Total E&P Norge (3.69 percent); and ConocoPhillips Skandinavia (1.62

Royal Dutch Shell plc ("Shell" )has announces the successful completion of the acquisition of Repsol S.A.'s ("Repsol") liquefied natural gas (LNG) portfolio outside North America for a headline cash consideration of $4.1 billion. As part of the transaction, Shell will also assume $1.6 billion of balance sheet liabilities relating to existing leases for LNG ship charters, substantially increasing the shipping capacity available to Shell's world-class LNG marketing business.

The deal gives Shell an additional 7.2 million tonnes per annum (mtpa) of directly managed LNG volumes. The company's already diverse and flexible portfolio will be boosted with LNG supply in the Atlantic from Trinidad & Tobago, and in the Pacific from Peru. In addition, it immediately contributes additional cash flow, while requiring limited on-going capital expenditure.
Since the announcement of the transaction in February 2013, certain value adjustments have been made in accordance with the terms of the sales and purchase agreement. These are expected to lead to a net cash purchase price of $3.8 billion (subject to post closing adjustments), compared to purchase price of $4.4 billion announced in February 2013, and balance sheet liabilities of $1.6 billion, compared to $1.8 billion at the initial announcement. This includes the exercise of pre-emption rights of the BBE power plant in Spain by an existing partner as well as other adjustments such as the financial performance of the portfolio and working capital movements since the effective date of 1st October 2012.
The deal closed in 2014. Shell's capital investment in Q4 2013 will reflect $3.4 billion for this transaction with the remainder of $2.0 billion booked in 2014 of which $1.6 billion is a non cash item relating to finance ship leases.

The transaction will add:
a) Net 4.2 mtpa equity LNG plant capacity, increasing the company's equity LNG capacity by around 20%, from 22 to 26 mtpa.
• Atlantic LNG trains 1-4; 14.8 mtpa capacity on a 100% basis (20-25% equity per train); operated by Atlantic LNG Company of Trinidad and Tobago.
• Peru LNG 4.45 mtpa capacity, on a 100% basis (acquisition: 20% equity: 100% offtake); operated by Peru LNG Company.
• A fleet of LNG carriers, comprising both long term and short term time charters.
b) 7.2 mtpa of LNG volumes through long term off-take agreements.
c) As part of this agreement, as previously disclosed, Shell has committed to supply around 0.1 mtpa of LNG to Repsol's Canaport LNG terminal in Canada over a period of 10 years.

The Petrobras LNG Regasification Terminal in Bahia brings greater flexibility and assurances to natural gas supplies in Brazil, with regasification capacity now up to 41 million m³/day.

At precisely 1:13 pm on Friday (January 24, 2014), Petrobras added to the Brazilian gas pipeline network the first regasified LNG (Liquefied Natural Gas) from its new Regasification Terminal, located in Baía de Todos os Santos, Salvador, in the state of Bahia. The Bahia Regasification Terminal (TRBA) has a regasification capacity of 14 million m³/day of natural gas. With the new terminal now in operation, Petrobras' natural gas regasification capacity has risen from 27 million m³/day to 41 million m³/day, equivalent to almost one and half times the capacity to import gas from Bolivia.

The company is already operating the regasification terminals at Pecém (Ceará state) and Guanabara Bay (Rio de Janeiro state) with their respective regasification capacities of 7 million m³/day and 20 million m³/day of natural gas.

The LNG is imported from various suppliers around the world in order to meet the domestic demand for natural gas, with a view to providing greater flexibility and guaranteeing supplies, thereby increasing the country's energy security, which is essential to encourage new investment.

The TRBA involved an investment of around R$ 1 billion and is the country's third LNG regasification terminal. An ingredient of the federal government's Growth Acceleration Program (PAC), construction of the terminal was begun in 2012 and it was completed on time and generated 3,623 direct jobs in the region, while achieving a level of domestic content in its equipment and services of approximately 90%.

Faroe Petroleum, the independent oil and gas company focusing principally on exploration, appraisal and production opportunities in the Atlantic margin, the North Sea and Norway, is pleased to announce that it has been awarded 10 new prospective exploration licenses, including two operatorships, under the 2013 Norwegian APA (Awards in Pre-defined Areas) License Round on the Norwegian Continental Shelf. These 10 licenses equate to the largest number awarded in this APA round, equal with Centrica and Statoil.

Northern North Sea
The Company has been awarded one license in the northern North Sea. This license offers exciting exploration opportunities in an area with established nearby production infrastructure in the Brage Field:

License PL740 Brasse – Blocks 30/9 and 31/7: Faroe (50% and operator) and Core Energy AS ("Core") (50%). The Brasse Prospect in the Upper Jurassic Sognefjord formation is located south of the Brage field on the possible migration route into Brage. The prospect holds significant upside potential in stacked reservoirs in Upper and Middle Jurassic. The work program will be focused on reducing risk by improving the existing 3D seismic dataset through re-processing.

North Sea
The Company has been awarded four licenses in the North Sea, where the Company already holds a number of licenses, including the Butch oil field, discovered in 2011:

License PL731 Freya – Block 8/10: Faroe (30%), Centrica Resources (Norge) AS ("Centrica") (40% and operator) and Tullow Oil Norge AS ("Tullow") (30%). This North Sea license is located immediately east of the PL405 license which contains the Butch Discovery (Faroe Petroleum 15%). This license extension contains the Upper Jurassic Freya Prospect, which extends into the PL666 Percy license and which is held by the same license group. The work commitment is to perform and complete technical studies already initiated in the PL668 Etta license.
License PL729 Katie – Block 2/1: Faroe (30%), Centrica (40% and operator) and Tullow (30%). The Katie Prospect is an Ula sandstone prospect that extends over the PL668 Etta license and into the new awarded acreage in PL729. The partnership and work program are aligned with the PL668 license, and a future well on the Katie Prospect has potential to be placed in either of the two licenses.

License PL670 B Betula extension – Block 7/11: Faroe (25%), Tullow (30% and operator), Centrica (25%) and Concedo ASA (20%). The Betula Prospect is an exciting opportunity in a mature and prolific area in the vicinity of the Jurassic Ula oil field in the Central North Sea. This new license covers the southern extent of the Betula Prospect. The work program is aligned with the PL670 Betula license, and has no additional work commitments.

License PL733 Adonia – Blocks 9/5, 9/8 and 9/9: Faroe (50% and operator) and Explora Petroleum AS (50%). Two Middle Jurassic leads have been identified on a salt ridge west of the Faroe Petroleum-operated PL620 Lola license located in the Egersund basin. The license contains Adonia, a down-thrown trap, and Stella, an up-thrown three-way closure. The work program is to perform technical studies and consider carrying out a 3D seismic acquisition.

Norwegian Sea
The Company has been awarded one new license in a very exciting immature exploration area east of the giant Ormen Lange field in the North Sea.

License PL749 Seychelles and Maldives– Blocks 6306/4 and 6306/5: Faroe (20%), Centrica (40% and operator), VNG Norge AS ("VNG") (20%) and Petoro AS (20%). The Seychelles and Maldives prospects are located on a structural nose on a down-faulted terrace from the Frøya High. Potential reservoirs are in the Upper and Middle Jurassic. The prospects have been defined based on limited seismic coverage with significant potential for de-risking using new seismic data. The work program consists of 3D seismic acquisition to improve the understanding of the structural and sedimentological setting of the area.

Norwegian Sea, Halten Terrace Area
The Company has been awarded four new licenses in the prolific Halten Terrace hydrocarbon province of the Norwegian Sea. The main focus for all of these licenses is the further exploration of the Cretaceous Lange Formation sandstones, as discovered in the Solberg/Rodriguez discovery, which Faroe announced in January 2013:

License PL475 D Solberg South extension – Block 6407/1: Faroe (30%), Wintershall Norge AS ("Wintershall") (35% and operator), Centrica (20%) and Moeco Oil & Gas Norge AS (15%). This area represents part of the southern extension of the Solberg sandstone system and covers part of the potential down-dip extension of the Solberg accumulation, which was discovered in PL475 in early 2013, and which is the target of the Solberg appraisal well scheduled for drilling in Q1 2014. The work program is aligned with the PL475 Solberg license, with no additional work commitments.
License PL590 B Solberg North extension – Block 6507/11: Faroe (30%), North Energy ASA (30% and operator), Wintershall (30%) and Spike Exploration Holdings AS (10%). This area represents a northern extension of the Solberg sandstone system, which extends across PL590 and into the area of the new license. The area covers part of the potential up dip part of the Solberg accumulation, discovered in PL475. The work program is aligned with the PL590 Milagro license, with no additional work commitments.

License PL754 Aurora – Blocks 6407/2: Faroe (30%), Rocksource ASA (40% and operator) and Centrica (30%). A Cretaceous Lange Formation anomaly has been mapped up dip of the southern extension of the Solberg sandstone system. This is a region where Faroe has a long history and experience through our continuing pursuit of Cretaceous sand systems on the Halten Terrace. The work program will be focused on reducing risk by improving the existing 3D seismic data-set through re-processing.
License PL753 Zircon – Blocks 6407/7 and 6407/8: Faroe (30%), VNG (40% and operator) and Core (30%). This license is located in close proximity to the Njord Field and the PL348 license (Hyme Field and Snilehorn Discovery). An anomaly on 2D seismic in the Cretaceous Lange Formation similar to what has been observed in the Solberg Discovery (PL475) has been identified, covering a large area close to the Njord Field. The work program consists of 3D seismic acquisition.

Graham Stewart, Chief Executive of Faroe Petroleum, commented:

"We are delighted with these license awards, which add considerable new potential to our forward drilling program. Faroe has again been very successful in its license application strategy, and this award is the largest to date for the Company, and indeed in the entire APA round, alongside Statoil and Centrica. This demonstrates the strength of our reputation in Norway and further positions us as having one of the largest license portfolios on the Norwegian Continental Shelf.

"Faroe Petroleum has built a strong and sustainable exploration company, with Norway at center stage. Our significant Norwegian portfolio has a diversified mix of both near-field and frontier opportunities, from which we can high-grade the best prospects for drilling. The combined advantages of Norway's progressive and highly successful fiscal incentivisation for exploration and our own cash generating production ensure we can continue to make Norway a key part of our value creating business strategy."

Subsea Riser Products (SRP), an Acteon company, has won a multi-million pound contract with Total to supply a 3,500-psi drilling riser and deployment tooling for the Moho Nord project in The Republic of the Congo. This is the first time that Total, an oil and gas super-major, has awarded SRP a direct contract.

The scope of the contract includes 43 joints for drilling from a tension leg platform in a water depth of 780 m, located 75 km off the coast of Pointe Noire. Manufacturing and assembly work will take place in the UK and mainland Europe, and the equipment will be delivered by March 2015. The project will call on skills from a range of departments within SRP, including design, engineering, quality and procurement.

Johnny Shield, managing director, SRP, said, "This is a major project award that confirms our ability to engineer and provide complex turnkey riser projects directly to major oil and gas companies. This contract provides a solid base from which SRP will grow and provide its riser engineering and procurement capability offering to other companies. A key aspect of the contract win was our ability to deliver to the highest quality level against an aggressive schedule at a competitive price."

Commentary from Bentek Energy Director of Energy Analysis Jack Weixel:
Platts oil and gas analytics unit, Bentek Energy, said that natural gas demand hit yet another milestone on Tuesday as the U.S. endured another day of subzero weather. Gas delivered to consumers across the U.S. on Tuesday hit 134.3 Bcf/d – supplanting Monday's short lived record demand mark of 130.4 Bcf/d. The increase in demand was most notable in the Northeast where residential and commercial demand jumped 30% from the prior day. Bentek Director of Energy Analysis, Jack Weixel, said that natural gas use for consumers is up across the board, regardless of weather, and that big temperature swings in the future will cause the same result. "You've got this massive supply source in the Marcellus, about 300 miles west of major New York and Mid-Atlantic market places, and prices of natural gas nationally have moderated considerably over the past five years, so utilities are leaning on the fuel as a go-to fuel source," said Mr. Weixel. "When cold strikes and more people are connected to the system, you have more systemic gas demand, so it becomes a pipeline capacity issue." The lack of pipeline capacity into New York could be responsible for the massive spot price increases seen in day ahead trading for Tuesday. Platts price data indicates that day ahead prices for gas delivered on Wednesday have decreased dramatically as demand is forecast to ease. Mr. Weixel concluded by saying that 'this is not the last time we'll see these big daily spikes in price, probably not the last time this winter, or at least until more capacity is built to serve an increasing customer base."

Platts Natural Gas Alert article which ran on Monday 1/7/14:
NE US SPOT NATURAL GAS PRICES FALL NEARLY $37/MMBTU ON WARMER WEATHER
Houston (Platts)--7Jan2014/1019 am EST/1519 GMT
Some spot natural gas prices in the US Northeast fell nearly $37/MMBtu
Tuesday, with forecasts calling for warmer temperatures Wednesday following a
bout of extremely cold weather.
Transcontinental Gas Pipeline Zone 6 non-New York sank $36.80 to average
in the lower $35.00s/MMBtu on IntercontinentalExchange, after hitting a new
all-time high Monday.
Transco Zone 6 New York dropped $20.79 to average in the lower
$32.10s/MMBtu, narrowing its discount to non-New York to $2.90 from $18.91
Monday.
Texas Eastern M3 dropped $25.26 to average in the lower $15.00s/MMBtu.
Algonquin Gas Transmission dropped $7 to average in the lower
$26.50s/MMBtu, with Tennessee Gas Pipe Line Zone 6-200 leg down $6.35 to
average in the upper $27.60s/MMBtu.
Iroquois Gas Transmission, receipts dropped $17.62 to average in the
mid-$19.00s/MMBtu, with Iroquois Zone 2 down $14.63 to average in the lower
$23.10s/MMbtu.
Other Northeast prices were mixed, with production region points up as
much as $1.30 as multiple pipeline companies posted notices restricting
secondary nominations amid the record demand seen Monday.
A mass of cold air swept into the northern US Monday, bringing wind
chills down to the minus 40s Fahrenheit from western New York to Wisconsin,
boosting spot natural gas prices to record highs in Monday trading.
By Wednesday, high temperatures below zero will be virtually gone from
the lower 48 states, said a report from The Weather Channel. By Thursday,
highs in the teens, 20s, or 30s will come to the Great Lakes and northeast
areas, the report said.
Washington was forecast to have a high of 27 F Wednesday following a high
of 14 F Tuesday. New York will see a high of 27 F, following a high of 13 F
Tuesday.
Platts unit Bentek Energy projected total northeast load to drop to 34.4
Bcf Wednesday, from 38.9 Bcf Tuesday.

Monday's Platts-Bentek's Gas Daily Market Fundamentals:
Demand surges to new record high of 134 Bcf/d

Demand continues to surge to 134.3 Bcf/d, breaking the record of 130.4 Bcf/d
set Monday, as frigid temperatures expand eastward.
The day-on-day gain can be attributed primarily to an 10.3-Bcf/d strengthening in Northeast
residential/commercial demand, which rose to 28.8 Bcf/d from 18.5 Bcf/d.
Total Midwest demand remains strong, falling only 2 Bcf/d to 31.3 Bcf/d, which
still ranks as the fourth-highest level since 2005.
The cold snap will start to taper off starting Wednesday, providing relief to the Midwest and Northeast
and likely pushing total demand below 100 Bcf/d by Friday. Production is up
roughly 0.3 Bcf/d, with a rebound of nearly 0.5 Bcf/d in the Fayetteville
basin, after its production was revised 0.7 Bcf/d lower in Monday's I2 cycle,
indicating possible freeze-offs.

LGO announces that the Company has now started mobilization for the construction of the first drilling sites following the Certificate of Environmental Compliance ("CEC") for 30 new development wells having been formally issued by the Environmental Management Agency of Trinidad and Tobago.  The work at its 100% Goudron Field will start almost immediately and LGO expects to spud the first new well on Goudron since the 1980's as soon as the preparatory works are completed.

Highlights:

·    CEC to drill 30 new wells at the Goudron Field formally approved.

·    Goudron Field has 2P oil reserves of 7.2 million barrels ("mmbbls") and further contingent oil reserves of 63 mmbbls, with an oil-in-place of 127 mmbbls (2P).

·    The first new well, H-18E J-7, will be drilled to approximately 4,000 feet and is targeting net oil sands of 250 feet in the Gros Morne sandstones and a further 100 feet in the Lower Cruse sandstone.

·    Infrastructure improvements to handle the increase in oil production at Goudron are nearing completion.

·    An additional 2,000 barrels of oil sales capacity has also been approved with the CEC.

Neil Ritson, LGO Chief Executive, commented:

"The next phase of our re-development at Goudron is about to get underway.  This is a very exciting phase for the Company and the drilling of these new wells will result in a substantial increase in the Company's oil production.  The minimal facilities that were in place when LGO acquired the asset in 2012 have been significantly upgraded to support the 65 well reactivations carried out so far and the 30 new wells that we are about to drill.  The approval in this CEC of an additional 2,000 barrel sales tank is also critical to medium term growth."

Drilling Update

The 30 new wells approved for the Goudron Field will be targeting known productive intervals in the Goudron, Gros Morne and Lower Cruse sandstones. Each new well is expected to take 7 to 10 days to drill.  Well evaluation and final completion will be undertaken after the rig has been moved to the next well and initial production is planned to commence within 60 days of spudding each well.

A drilling contractor has been selected and other services are being contracted at this time.  The chosen rig is currently undergoing upgrade work and is expected to be available to mobilize to Goudron in late February 2014.

Drill pad construction contracts will now be awarded in conjunction with completing the access road repairs currently underway to accommodate the transport of heavy machinery. A permanent camp, including workshops, offices and off duty rest accommodation has been constructed and is currently being commissioned in readiness for the commencement of the drilling program.

Infrastructure improvement work at the field continues with the reactivation of Tank Battery Station No. 207 nearing completion where the existing tanks have been refurbished to provide an additional 1,000 barrels of storage and water treatment in preparation for the expected increase in oil production.

The first well, provisionally designated H-18E J-7, lies within an area of the field where unrecovered oil is expected to be present in the Gros Morne and Lower Cruse sandstones.  The Lower Cruse at a depth of 2,800 feet sub-sea is the primary target of the well, which will then be deepened to approximately 4,000 feet to ensure all productive horizons are intersected.  Based on the offset wells; including GY-188 (250 feet to the north-east) and GY-64 (170 feet to the north-west), net oil sand of 250 feet is prognosed in the Gros Morne and a further 100 feet in the Lower Cruse. 

LGO is now evaluating the merits of drilling the 30 wells in a continuous program.  Previously, only 2 wells were intended in the next phase to be followed by the balance of the wells after an evaluation phase, however, the deferred start, presence of adequate funding and various economies of scale suggest that a longer continuous drilling program will give improved economic returns.

Goudron Field Reserves

In July 2012, Challenge Energy Limited ("Challenge") independently assessed the Proven and Probable (2P) recoverable reserves from primary production, prior to new drilling, of 7.2 million barrels (mmbbls) and Proven, Probable and Possible reserves (3P) of 30.4 mmbbls.  Challenge's estimates are tabulated below.

It is anticipated that the execution of this 30 well development campaign will move the majority of the 2P reserves to the Proven category and a new competent persons report will be commissioned in the second quarter 2014, once new drilling results have been obtained.

No secondary or enhanced oil recovery, such as water-flooding, had been assumed in these previously reported reserves; although nearby analogous fields in Trinidad have had successful water-flood projects.  Overall recovery without water-flooding is estimated to be just 10% of the oil-in-place which has been computed to be up to 350 mmbbls in the 3P case.  Challenge recognizes a further 63 mmbbls of Contingent Resources associated with a future water flooding project.  If such a project was undertaken it is believed that the overall recovery factor would rise to about 30%.

IPSC with Petrotrin

LGO has a 100% working interest in the Incremental Production Service Contract ("IPSC") granted by the Petroleum Company of Trinidad and Tobago ("Petrotrin") which gives LGO rights to produce oil from the 2,875 acres (11.4 square km) Goudron Block down to 5,000 feet subsea.  The Goudron Field is be operated by Goudron E&P Limited, a wholly owned subsidiary of LGO.

The IPSC was effective from 18 November 2009 and had an initial term of 10 years. On 14 August 2013, LGO successfully concluded an agreement with Petrotrin to reduce substantially the overriding royalty rates associated with oil production from Goudron and to extend the contract by at least five (5) years to November 2024 in consideration for LGO undertaking additional drilling.

The revised IPSC agreement, effective from 1 August 2013, included a reduction of overriding royalty rates for existing and future production in order to incentivize further development and exploration in the Goudron Block.  The 30 well re-development program commencing in 2014 is a direct result of that agreement and will meet, and greatly exceed, the additional commitments made at that time. The new agreement provides that oil production between the First Tranche Oil, which is currently approximately 40 barrels per day ("bopd"), and a rate of about 150 bopd (reducing annually by 2%) will receive a relative reduction of approximately 20% in the overriding royalty paid to Petrotrin. Production above 150 bopd, which Goudron is already exceeding, has a more significant reduction equivalent to approximately 45% of the previously applicable rate at the current oil price.

Language was also included in the revised IPSC that, subject to mutual agreement on work programs, will allow the IPSC to be extended for a period of 5 years in 2019. This extension is significant as it will allow the Company to effectively instigate Enhanced Oil Recovery programs in order to bring the 30 mmbbls of Possible (P3) reserves and some of the 63 mmbbls of Contingent Resources in to Proven (P1) and Probable (P2) reserves over the coming years.

LGO holds a 100% interest in the Goudron Field and all such estimates therefore both gross and net to the Company.

Chevron Corporation (NYSE: CVX) has announced that its U.K. subsidiary, Chevron North Sea Limited, has reached a final investment decision and received approval from the U.K. government to proceed with the development of the Alder Field in the Central North Sea. The project has a planned design capacity of 110 million cubic feet of natural gas and 14,000 barrels of condensate per day. First production is expected in 2016.

"The Alder Field development is an important milestone in support of our strategic plan to profitably grow production and is among our solid queue of major capital projects that will deliver value to shareholders," said Chevron vice chairman George Kirkland.

"The Alder project builds on Chevron's already well-established presence in the U.K. energy development sector," said Todd Levy, president of Chevron Europe, Eurasia and Middle East Exploration and Production. "For more than 50 years Chevron has been active in the U.K.'s oil and gas industry, and we will continue to play a role in developing the region's natural resources."

Discovered in 1975, development has recently been enabled by innovative technologies to manage the high-pressure high-temperature gas condensate field located in Block 15/29a, in a water depth of 492 feet (150 meters) approximately 100 miles (160 kilometers) from the Scottish coastline and 37 miles (60 kilometers) from the U.K./Norway median line.

The field will be developed via a single subsea well tied back to the existing Britannia Platform, a distance of 17 miles (28 kilometers).

Chevron North Sea Limited operates the project and has a 73.684 percent interest, with co-venturer ConocoPhillips (U.K.) Limited (26.316 percent).

By using the Earth’s magnetic field, combined with new innovative technology, oil and gas drilling companies are increasing oilfield productivity while reducing development costs and environmental impacts.

An article in the fall 2013 issue of Oilfield Review highlights this technology and its applications across the world. It also discusses the public-private collaboration between the U.S. Geological Survey and partners to successfully implement the technology.

These days, multiple reservoirs of oil and gas can be accessed from a single platform by drilling vertically and then horizontally. Drill operators need to know which way their drill bits are going to maximize oil production and avoid collisions with other wells. One way to accomplish this important task is to install a magnetometer—a sort of modern-day “compass”—in a drill-string instrument package that follows the drill bit.

The USGS plays a unique role by monitoring the geomagnetic field every single second at magnetic observatories throughout the country. Through a process called geomagnetic referencing, simultaneous measurements of the magnetic field in the drill hole are combined with those from magnetic observatories at the Earth’s surface to produce a highly accurate estimate of the drill bit position and direction.

The Earth’s magnetic field changes all the time across the world as a result of factors like periodic daily tides or rapid magnetic storms that are related to the 11-year sunspot solar cycle. And at high latitudes, such as in northern Alaska or the North Sea, the geomagnetic field can be very active and can change dramatically during magnetic storms.

“Drill-bit positioning requires directional accuracy of a fraction of a degree, and this can be accomplished with advanced technology and expert understanding of the Earth’s dynamic magnetic field,” said Carol A. Finn, USGS Geomagnetism Group Leader. “USGS operational systems measure the magnetic field on a continuous basis. These data are provided as a service to research scientists, civilian and defense government agencies, and to customers in the private sector, including the oil and gas drilling industry.”

The USGS Geomagnetism Program monitors variations in the Earth’s magnetic field through a network of 14 ground-based observatories around the United States and its territories. There are many customers for geomagnetism data, since the variable conditions of space weather can interfere with radio communication, GPS systems, electric power grids, the operation and orientation of satellites, and even air travel as high altitude pilots and astronauts can be subjected to enhanced levels of radiation.

Internationally, the USGS magnetic observatory network is part of the global INTERMAGNET network. Domestically, the USGS Geomagnetism Program works cooperatively with government partners within the U.S. National Space Weather Program, including NOAA and the Air Force Weather Agency, and with private companies that are affected by space weather and geomagnetic activity.

Read the Oilfield Review article: Geomagnetic referencing - The real-time compass for directional drillers.

Read a USGS factsheet: Monitoring the Earth’s dynamic magnetic field.

Watch a 7 minute video about the USGS Geomagnetism Program.

Eni has been present in Norway since 1965, with current production standing at approximately 110,000 boe per day through its subsidiary Eni Norge AS.

San Donato Milanese (Milan), 9 December, 2013 – Eni has made a new offshore oil and gas discovery in the Norwegian Barents Sea, approximately 240km from Hammerfest.
The well, which is located in the Skavl prospect in the PL532 license, has been drilled five kilometers south of the Johan Castberg area. It was drilled in approximately 349 meters of water and reached a target depth of 1,700 meters.

The well has confirmed good quality oil and gas in Jurassic and Triassic sandstone, with volumes of recoverable oil estimated at between 20 and 50 million barrels. The discovery is part of Eni's joint venture exploration activity to develop the Johan Castberg field.

Following completion of Skavl, the drilling rig will move 16 kilometers north where it will continue its exploration campaign in the execution of an additional exploration well on the prospect of Kramsnø. 
Statoil is the operator of production license PL532 with a 50% stake; the remaining shares are held by Eni Norge AS (30%) and Petoro AS (20%).

Eni has been present in Norway since 1965, with current production standing at approximately 110,000 boe per day through its subsidiary Eni Norge AS. Eni is operator of the ongoing development of the first oil field in the Barents Sea, the important Goliat discovery, and of the Marulk gas field in the Norwegian Sea. Furthermore, in Norway Eni has interests in the country in a number of exploration licenses and fields under development and in operation, including Ekofisk, Norne, Åsgard, Heidrun, Kristin, Mikkel and Urd.