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.

Total announces the signature of a farm-in agreement with InterOil Corporation that gives it a 61.3% interest in Petroleum Retention License (PRL) 15 in Papua New Guinea. The Elk and Antelope gas fields, two of the biggest finds in the Asia-Pacific region in recent years, were discovered in the license in 2006 and 2009 respectively.

Total and InterOil Corporation retain the flexibility to farm-down an aggregate of up to a 19.3% interest (before any election by the government to exercise its option to join the project with a 22.5% interest) to a strategic partner.

The common objective of Total, who will operate the project, and InterOil, is to complete the delineation of the two discoveries and to continue to explore for new resources in the license area. Depending on the results, this could lead to a final investment decision by 2016 for the development of the fields and the construction of a liquefaction plant located onshore on the Gulf of Papua.

In addition, Total has an option to take an interest in Petroleum Prospecting Licenses PPL 236, PPL 237 and PPL 238 in the same area.

"Following Total's entry into exploration in Papua New Guinea in 2012, this new acquisition of an interest in significant discovered resources is an exciting opportunity for Total to develop a new gas production and liquefaction hub in the Asia-Pacific region, where gas demand is very dynamic", stated Yves-Louis Darricarrère, President Upstream at Total. "Total will leverage its technology and experience in major LNG projects to reinforce its long-term production post-2020."

Total will pay $470 million for a 42% interest (32.5% if the government executes its option to join the project) with a contingent payment estimated by Total at approximately $590 million. The transaction remains subject to the approval of the Papua New Guinea government.

Total in Papua New Guinea
In October 2012, Total acquired from Oil Search Limited a 40% stake in the PPL 234 and PPL 244 offshore permits, 50% in the PRL 10 offshore permit and an option for 35% in the PPL 338 and PPL 339 onshore permits (in the same area as the Elk and Antelope gas fields and PPLs 236, PPL 237 and PPL 238).

In April 2012, Total Marketing & Services created a new affiliate in Papua New Guinea, with offices in Port Moresby. Total Marketing & Services had been marketing lubricants in the country via a distributor arrangement for several years. The new affiliate will allow Total to more effectively support its mining and manufacturing customers in implementing their development projects in Papua New Guinea, which is enjoying strong economic growth.

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.

Statoil and co-venturer ExxonMobil announce its fifth discovery in Block 2 offshore Tanzania.

The discovery of an additional 2-3 trillion cubic feet (Tcf)* of natural gas in place in the Mronge-1 well brings the total of in-place volumes up to 17-20 Tcf in Block 2.

Mronge-1 is drilled by the drillship Discoverer Americas, and the site is located 20 kilometers north of the Zafarani discovery, and at 2,500-meter water depth.

"We have initiated a new and ambitious drilling campaign offshore Tanzania following four successful discoveries during the first drilling phase. The Mronge-1 well discovered additional gas volumes and furthers the potential for a natural gas development in Tanzania. The new drilling program also allows us to fully explore the remaining exploration potential in Block 2," says Nick Maden, senior vice president for Statoil's exploration activities in the Western hemisphere.

The Mronge-1 well discovered gas at two separate levels. The main accumulation is at the same stratigraphic level as proven in the Zafarani-1 well in Block 2. The Zafarani-1 discovery was made in 2012 and was a play opener for the block.

The secondary accumulation was encountered in a separate, younger gas bearing reservoir, in a play which previously has not been tested in Block 2.

The Mronge-1 discovery is the venture's fifth discovery in Block 2. It was preceded by three successful high-impact gas discoveries during the first drilling phase with Tangawizi-1, Zafarani-1 and Lavani-1, and a deeper discovery in a separate reservoir in Lavani-2.

"These are high value resources. The attractiveness is also demonstrated by a recent asset transaction in the neighboring block. The discoveries also demonstrate how Statoil's strategy of focusing on high-impact opportunities is paying off and supports the company's ambition for international growth," Maden says.

"The Tanzania government is pleased to learn about additional gas resources discovered in Block 2," says Hon. Prof. Sospeter Muhongo, Minister for Energy and Minerals in Tanzania.

The Statoil-operated partnership started its new drilling campaign in Block 2 in September 2013. In addition to Mronge-1, the campaign includes drilling of several new prospects and appraisal of previous discoveries. Following Mronge-1, the partnership is scheduled to appraise the 2012 Zafarani discovery.

Statoil operates the license on Block 2 on behalf of Tanzania Petroleum Development

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.

A group comprised of 17 oil and gas companies has established a project for joint seismic acquisition in the southeastern Barents Sea. Statoil is the operator of the project.

Seismic vessel Ramford Vanguard. (Photo: Ole Jørgen Bratland)

At the request of the Norwegian Ministry of Petroleum and Energy (MPE), the industry, via the Norwegian Oil and Gas Association, has taken the initiative to jointly acquire seismic 3D data from the blocks in the southeastern Barents Sea that will be announced in the 23rd licensing round for the Norwegian continental shelf (NCS) in 2014.

This is the first new area on the NCS to be opened since 1994. Thirty companies showed interest in participating in such a collaboration.

17 of these companies signed an agreement to establish a joint project for planning and implementing the acquisition. As the largest operator on the Norwegian shelf Statoil has taken on the operator role.

"Coordinated seismic acquisition has several advantages. It will ensure very good data quality, since the industry to a much greater extent will be able to utilise the companies' collective professional expertise within geological understanding and seismic acquisition and processing. The initiative lays the foundation for fewer, well-planned operations, thus reducing acquisition costs and potential disadvantages for the fishing industry," says Gro G. Haatvedt, Statoil's senior vice president for exploration on the NCS.

"Interest in the Barents Sea has increased considerably in recent years, due in part to the discoveries in the Johan Castberg area. High-quality 3D data will be important to the industry in order to increase understanding of the area's potential."

When the authorities circulate the 23rd round nominated blocks for public consultation, other oil companies will get a new opportunity to engage in the project. It is expected that several companies will make use of this offer.

The project will immediately initiate a tender process for the seismic acquisition. The plan is for the seismic surveys to start in April 2014 and conclude in the autumn of the same year.

The companies who will be taking part from the beginning are BP, Chevron, ConocoPhillips, Det norske oljeselskap, Eni, GDF Suez, Idemitsu, Lukoil, Lundin, Norske Shell, PGNiG, Repsol, Spike, Statoil, Suncor, VNG and Wintershall.

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.

VAALCO Energy, Inc. (NYSE: EGY) has announced that the Company has received written confirmation from The Ministry of Petroleum of Angola that the available 40% working interest in Block 5, offshore Angola, has been assigned to Sonangol E.P., the National Concessionaire. The Ministry of Petroleum also confirmed that Sonangol E.P. will assign the aforementioned participating interest to its exploration and production affiliate, Sonangol P&P.

With this confirmation, VAALCO has begun the process of contacting drilling rig companies to secure a semi-submersible rig to commence the exploration phase of the pre-salt / post-salt Kwanza Basin program.

Steve Guidry, CEO, commented, "We are excited to begin drilling offshore Angola, especially given the recent significant discoveries made elsewhere in the Kwanza basin in which Block 5 is located. Having Sonangol as our partner, with their extensive knowledge of the basin, reaffirms our confidence in the potential of discovering commercial quantities of hydrocarbons on our 1.4 million acre concession."

Following the assignment, Sonangol and its affiliates will hold a 60% working interest in Block 5, comprising a 20% carried working interest and the newly assigned 40% participatory working interest. VAALCO, as operator, continues to hold a 40% operating working interest in Block 5.