Elliott Bay Design Group (EBDG), a leading naval architecture and marine engineering firm with offices in Seattle and Ketchikan, recently announced the delivery into service of the CAPE HORN, a Specialty Oilfield Vessel that it designed. EBDG partnered with Gulf of Mexico Operator SeaMar, LLC and Gulf Island Marine Fabricators on the class design and production engineering for the ship.

"We would like to congratulate our valued client, Darrel Plaisance of SeaMar, LLC on the delivery of their EB-220CC and the shipyard on a fine build," stated Gulf Coast General Manager, Keith Keller.

The design of the CAPE HORN was developed from concept to production in EBDG's Gulf Coast office and features an innovative tank farm unique to Specialty Design Oilfield Vessels. EBDG provided full design services including structural, mechanical, piping and outfitting design, and served as the primary point of contact for all regulatory body requests for information.

EBDG credits great teamwork, communication and project management expertise for the successful journey of the CAPE HORN from design to delivery and looks forward to a continued relationship with SeaMar, LLC and delivering its next vessel, the CAPE COD, into service.

CGG notes the announcement made by Technip that it no longer intends to file a tender offer for CGG.

Since the beginning of this unsolicited approach by Technip on November 10, CGG remained open to dialogue and studied all proposals of Technip taking into account the interests of its shareholders, clients and employees. The board of CGG considered that none of the proposed options were creating value for the Company and its stakeholders.

CGG remains confident in the ongoing execution and the success of its strategy as an independent company. CGG is showing a solid resilient operational performance as highlighted in the third quarter results with important progresses achieved and milestones met in the transformation plan and the strengthening of the balance sheet.

With this plan initiated one year ago, accelerated and intensified during the year 2014 and with priorities given to cash generation, CGG is in a position to weather current difficult market conditions while fully benefiting from future geoscience market rebound.

Statoil has been awarded four new exploration permits offshore New Zealand, building on its existing position. This deepens and diversifies Statoil's long-term portfolio.

The permits are awarded by the New Zealand government through the 2014 Block Offer. Statoil participates in three blocks in the East Coast and Pegasus basins as a partner, and takes on operatorship for one new permit next to existing acreage in the Reinga basin.

"The East Coast acreage adds another high-impact opportunity to our long-term portfolio, while the expansion in the Reinga basin secures access to potential upsides from our existing position. This is in line with our exploration strategy of early access at scale and deepening existing positions," says Erling Vågnes, Statoil's senior vice president for exploration in the Eastern hemisphere.

• Blocks 57083, 57085 and 57087 are awarded with Chevron as operator, both companies holding a 50% working interest. The permits are located in the East Coast and Pegasus basins, southeast off New Zealand's North Island. The permits cover more than 25,000 square kilometers and sit in water depths between 800 and 3,000 meters. The initial phase of the project will consist of data collection.

• Block 57057 is awarded to Statoil with a 100% working interest. It is located in the Reinga basin offshore Northland, adjacent to Statoil's existing exploration acreage. The permit covers sits approximately 100 kilometers offshore and covers an area of 1,670 square kilometers in water depths of around 1,500 meters. Statoil has committed to acquire 200 line kilometers of 2D seismic data within the permit.

Statoil entered New Zealand through the 2013 Block Offer, with the award of petroleum exploration permit 55781 in the Reinga basin.

Ceona, SURF contractor with heavy subsea construction capabilities, has bolstered its pioneering fleet of next generation vessels with the christening of its flagship asset, the Ceona Amazon, which has been delivered in less than two years of the letter of intent (LOI) for its construction being signed.

The game-changing Ceona Amazon has been internally designed at Ceona and purpose built to perform in multiple pipelay and operational modes. She also features a large storage capacity and heavy subsea construction capability with her versatility setting her apart as a deepwater field development asset.

Ceona Amazon 2 - Ceona Amazon at sea trials in Bremerhaven, Germany, 24th November 2014

Shipbuilding specialist Lloyd Werft successfully delivered the Ceona Amazon on schedule in Bremerhaven where the vessel was officially christened yesterday (Wednesday, December 3) by her Godmother, Mrs Cynthia Huber from Houston, Texas.

Lloyd Werft delivered the Ceona Amazon within time and budget, and the vessel has also successfully undergone sea trials ahead of schedule.

Steve Preston, chief executive officer at Ceona, which has expanded its geographic footprint in West Africa, praised the teams involved in executing the Ceona Amazon development to the highest level: "Lloyd Werft has completed the vessel build and outfitting in just under two years of the LOI and to an extremely high quality. This is a stunning achievement by industry standards and a testament to their expertise and ability."

"I would also like to pay tribute to all our engineers and managers at Ceona who developed the concept for the Ceona Amazon design in-house, and have shown complete dedication to ensuring the building of a ground-breaking field development vessel in record time. This achievement underlines Ceona's vision for bringing new, cost-effective subsea services to oil & gas operators from small to medium-sized independents, national and international oil companies."

Rüdiger Pallentin, chairman of the Board of Lloyd Werft, added: "The Ceona Amazon is a masterpiece of shipbuilding, built by experts for experts with team-playing site teams from both Ceona and Lloyd Werft. We are proud and happy to deliver the flagship of Ceona's fleet."

Following her christening, the Ceona Amazon will transfer to Huisman yard in Schiedam, The Netherlands, where she will ultimately be equipped with a 570 tonne multi-lay pipe tower and two heavy duty 400 tonne offshore cranes – all of which have already been built by Huisman, a global leader in lifting, drilling and subsea solutions, and are ready to be installed.

The innovative G-lay pipelay system, developed and patented by Ceona, features an inclinable lay spread with a top tension of 570 tonnes and a rigid firing line system. It combines the offshore assembly of rigid pipe joints along a traditional firing line, then plastic bending of the pipe through a route similar to that of a reel-lay vessel, completed by a vertical exit through the moonpool (J-lay).

With capacity to carry 8,500 tonnes of pipe, the Ceona Amazon will be able to lay rigid and flexible pipelines and umbilicals, and install heavy subsea structures or floaters (TLP, semi or FPSO) using its two 400 tonne subsea cranes working in tandem.

Stuart Cameron, chief operating officer at Ceona, said: "The Amazon's completion is a significant milestone for Ceona and for its clients. As our first-owned purpose-built vessel, it is a powerful asset that can execute complex logistical projects in remote, harsh and deepwater environments in one trip.

"The vessel is ideally suited to the deeper waters of West Africa, the Gulf of Mexico and Brazil. The Amazon also brings our clients a new, cost-effective solution for their heavy subsea structure and floater installation services, via EPIC or Transportation and Installation (T&I) contracts."

He added: "After installation of the pipe-laying system and the twin 400 tonne cranes, the Amazon will be the second new vessel – after the Polar Onyx – Ceona will bring to the market on time and in less than a year. The Polar Onyx and the Normand Pacific have got significant experience in the Brazilian deepwaters for Petrobras, and for Independent, IOCs and NOCs in the Gulf of Mexico and in West Africa."

The Ceona Amazon is 199.4 metres long and 32.2 metres wide, drawing 8.0 metres with a gross tonnage of 33,000. She is due to enter service early 2015.

The vessel's outfitting at Bremerhaven followed successful floatation at Crist yard in Poland earlier this year in April before

Well management and performance improvement specialist Exceed has announced significant growth in 2014, reaching its target turnover of £15 million. In addition, the expansion of its Aberdeen team adds 10 new business support positions to the head office, including the appointment of a global business development manager. Founded in 2005, the Aberdeen-based company now employs a team of 75 with an international presence in Canada, Ghana, Kenya, Myanmar and Malaysia.

During the course of 2014 Exceed has expanded its client portfolio, resulting in a contracts value in excess of £5million, and is targeting business growth in new strategic markets in 2015.

Ian Mills, Exceed founder and director & Al Brockie, Exceed well management director

Exceed established an impressive track record as a performance improvement specialist before diversifying in 2009 to launch the industry's first wells management team to focus on deepwater well delivery, delivering projects in the Black Sea, East Mediterranean and Indonesia. The company continues to trail blaze, currently planning the very first deepwater campaign in Myanmar, expected to commence in early 2015.

The establishment of Exceed Canada in 2013 followed an agreement with two Canadian operators to provide high-calibre wells teams to support their existing drilling programmes. Exceed now has a team of harsh environment drilling experts supporting operations offshore on three rigs East Coast Canada.

In keeping with Exceed's strategy of client demand-led growth and diversification, a new enterprise is being established in Ghana driven by a high degree of confidence in the growth of the region following the announcement of the TEN deepwater field development offshore Ghana and other emerging opportunities in the Gulf of Guinea.

Exceed founder and director Ian Mills, who has 30 years' experience in the oil and gas industry including senior drilling roles at Shell and BP, said: "This year, we have experienced an increase in client-led enquiries across the business and as a result of the increased number of projects, we have invested heavily in our recruitment.

"2014 has been an exciting year for the company, with new projects enabling us to build on our international footprint while strengthening our presence in Canada and Africa. In 2015, our aim will be to look at further prospects in South East Asia and Brazil. We are also excited by the contracts we have been awarded and delivered in Iraq and Kenya which reinforces our industry reputation. The fact that we have been requested to support land-based well construction projects, which are typically much lower cost operation, highlights the clients' belief and commitment in our performance improvement solutions."

Exceed's Performance Improvement division has a proven track record of helping clients save millions of pounds by improving safety and increasing rig productive time, typically by 10-15%.

Exceed launched its well management service with the aim to become the world's preferred wells specialists partnering with clients to develop prospects without incidents and at the lowest possible cost of access. The key benefits to Exceed's target market – NOCs and the independent IOCs – include the calibre and training of its people and its track record for consistently delivering well objectives safely, on time, and within budget.

Also expects $1 billion in Group-wide restructuring charges over coming year

BP will present to investors its strategy and plans to the end of the decade and beyond for its Upstream oil and gas business.

The day-long presentation, led by BP's Upstream chief executive Lamar McKay, will provide an in-depth and detailed account of how BP is managing its Upstream business and its distinctive strategy for the long term. The presentation will also review the macro-environment and the context of recent developments in oil prices.

McKay and senior members of his upstream management team will share further insights into the depth and quality of the Group's resource base and investment portfolio, which underpin BP's long-term value proposition through the changes in the price environment.

"Although the current environment is challenging, BP is well-positioned to respond and manage our Upstream business for the long term," said Lamar McKay. "We expect to see growth from our conventional and deepwater assets and an increasing contribution from gas. And we also have a quality pipeline of opportunities that we believe are capable of extending underlying growth well beyond 2020. Our focus throughout will remain firmly on safe operations, execution efficiency and greater plant reliability."

BP also said that, as part of its wider ongoing Group-wide program to simplify across its Upstream and Downstream activities and corporate functions, it expects to incur non-operating restructuring charges of circa $1 billion in total over the next five quarters, including the current quarter. Details of these charges and further guidance on the program are expected to be given with each quarter's results.

Group Chief Executive Bob Dudley said: "We have already been working very hard over these past 18 months or so to right-size our organization as a result of completing more than $43 billion of divestments. We are clearly a more focused business now and, without diverting our attention from safety and reliability, our goal is to make BP even stronger and more competitive.

"The simplification work we have already done is serving us well as we face the tougher external environment. We continue to seek opportunities to eliminate duplication and stop unnecessary activity that is not fully aligned with the group's strategy."

As an integrated group, not all BP's businesses are equally exposed to the oil price. About one third of its Upstream projects around the world are operated under production sharing contracts and it is also investing in high quality gas projects which are typically less sensitive to oil price movements. Importantly, while BP approves projects at $80 a barrel, it also already tests each at $60 a barrel to understand the resilience of the portfolio at a range of prices. It will also continue to consider lower price sets as appropriate.

BP also has a strong balance sheet, with historically low gearing of 15% at the end of the third quarter of 2014, which provides time and flexibility to adjust to changes in the environment.

Across the Group, BP has said it will be looking to pare or re-phase capital expenditure without compromising safety or future growth. In October, BP told investors this could result in reductions of $1 billion to $2 billion in capital expenditure across the Group in 2015 against guidance of $24 billion to $26 billion laid out in March. This will be reviewed further as part of the 2015 plan, recognizing the current outlook for oil prices.

When oil prices fall, there is typically deflation in the industry as a whole. Together with its already greater focus on streamlining activity, this would be expected to further help BP align its cost base with its smaller footprint and reduced activity levels.

The Upstream team will today detail the business's track record of delivery as part of the Group's 10-point plan. Amongst the milestones, over the last three years, the Upstream has improved safety and reliability of operations; doubled exploration drilling activity; and rebuilt Gulf of Mexico production. It has also increased the rate of reinvestment; made $32 billion of divestments in the Upstream business alone; and, by year end, also expects to have delivered 15 new upstream projects with average operating cash margins double 2011 average.

Between now and 2020, the Upstream team's focus will be on delivery, through safe and reliable operations, strong execution in the existing base business, and the start-up of a suite of new projects which are expected to be capable of adding over 900,000 barrels of oil equivalent a day of net incremental production to BP's portfolio by 2020. BP will also be progressing opportunities expected to continue to drive underlying growth into the next decade as it builds out its well-established conventional and deepwater oil positions and a distinctive and material portfolio of gas options.

InterOil Corporation (NYSE: IOC) (POMSoX: IOC) has notified the Papua New Guinea Department of Petroleum and Energy of a discovery at the Bobcat-1 exploration well in PPL476.

The well was tested over an interval of about 320 meters of Kapau limestone, the upper section of the target reservoir, and flowed and flared hydrocarbons at surface.

Seismic mapping, wireline logging and testing results indicate the well is close to the gas-water contact in the transition zone.

Recently acquired seismic indicates the crest of the structure lies several kilometers west of the current well location and is several hundred meters higher than the current well depth.

Following these results, InterOil has notified the department that it has declared a total depth for the exploration well at 3,207 meters.

Future appraisal will include additional seismic and drilling. As the first part of the appraisal program, the company now intends to deepen the well to appraise reservoir quality.

Bobcat-1 is about 30km north-west of Elk-Antelope. InterOil holds a 78.1114% interest in the well and is operator. The remaining 21.8886% interest is held by minority interests.

LM Handling, an Acteon company, has provided handling expertise and equipment to support Acteon sister company, InterMoor, in the successful mooring installation of a floating production, storage and offloading (FPSO) unit for the China National Offshore Oil Corporation (CNOOC) operated Enping 24-2 oilfield in the South China Sea.

With LM Handling's lifting and handling expertise and equipment, a 12-pile anchor mooring system, consisting of three clusters of four mooring lines, was installed.

LM Handling provided its StabFrame-S in its extended configuration, pre-loaded with additional ballast to achieve a stable and safe install for the long mooring piles, and 84 and 60 in. internal lift tools. With a customised set of handling equipment, which enabled pile upending on the seabed, InterMoor was able to use a relatively lightweight construction vessel to install the piles quickly, efficiently and safely.

This mooring project represents LM Handling's first project in Chinese waters and second project for the StabFrame-S, which was specifically designed for lightweight South East Asia vessels. It is the fourth successful FPSO mooring project for LM Handling.

Robin van der Bij, managing director at LM Handling, said, "The Enping project has been a positive demonstration of how company collaboration can overcome difficult challenges and secure the smooth delivery of a project. It also means a fourth successful FPSO mooring installation for the StabFrame, which guides the piles into the location and stabilises them to assist with penetration."

InterMoor led the project, bringing together specialist services from Acteon group companies, including MENCK for the piling spread and newly acquired UTEC Survey for the data requirements.

Enping 24-2 oilfield is in the Pearl River Mouth basin of the South China Sea, which has water depths between 86 and 96 m. The main production facilities include a drilling and production platform, an FPSO and 17 producing wells. CNOOC has announced that two wells are producing approximately 8,000 bbls/d of crude oil. The project is expected to reach peak production of 40,000 bbls/d in 2017.

NYC-based PIRA Energy Group reports that the creeping stock surplus continues. In the U.S., overall commercial stocks built last week with the build in both products and crude.. In Japan, crude runs and imports are higher and crude stocks built fractionally. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

Creeping Stock Surplus Continues
Preliminary data is now in for end November and it shows that commercial oil inventories in the three major OECD markets – United States, Europe and Japan – drew just 12 million barrels (400 MB/D) compared to a year earlier 37 million barrel (1.2 MMB/D) decline. Commercial stocks in these markets began the fourth quarter 22 million barrels, or 1%, higher than the year earlier and have now ended November 76 million barrels, or 3.5% higher. This stock profile is consistent with PIRA's balances showing year on year supply growth outpacing demand growth by over 1 MMB/D. This imbalance grows even larger in 2015.

Data Issues Likely an Important Factor in Big U.S. Stock Build
Overall commercial stocks built last week with the build in both products and crude. Re-benchmarking occurred this week indexing the December 5 stock levels to the September PSM, which resulted in substantial upward revisions to stocks. Part of this adjustment could have inflated inventories and correspondingly deflated reported demand. An added factor could be the stock data for the prior Thanksgiving holiday week was underreported, thus distorting this week's stock change. Probably both factors are to blame but, nevertheless, this week's reported inventories reflect a growing surplus of inventory relative to last year.

Japanese Crude Runs and Imports Higher and Crude Stocks Built Fractionally
Crude runs were marginally higher on the week. Alignment with our planned turnaround schedules still looks good. Crude imports were higher and crude stocks built fractionally (0.2 MMBbls). Finished product stocks drew due to draws in all the products but jet.

Re-Weighting of Major Commodity Indices in January 2015 Boosts Brent but Lowers Natural Gas and European Gasoil
The S&P GSCI and the Bloomberg Commodity Index (BCI), the two major indices for passive investment in commodities, have recently announced the new weighting schemes that they will apply to their respective commodity indices effective January 2015. The BCI index will see $2.6 Billion flow into energy against a $0.5 Billion loss for GSCI. Natural gas is the big loser down $1.2 Billion in January 2015 vs. current levels, while Brent is the big winner picking up $2.6 Billion. WTI increases only $334 Million. Oil products over the same time period increase $407 Million. European gas oil is the other major loser in the re-weighting down 7 MMBBLs or $575 Million.

When Will the Bloodletting Stop?
Saudi Arabia's relinquishing its role as oil price anchor has caused a catastrophic decline in the demand for inventory which has resulted in oil prices collapsing. Both physical and financial "inventory" holders have been selling. The selling has had a snow ball effect because of a lack of liquidity, one of the consequences of Dodd Frank regulations, and ongoing producer hedging. With many U.S. shale oil producers under hedged in 2016, with say 15% coverage, versus 40-50% for 2015, the selling pressure will not end until prices drop to the level where hedging is uneconomic.

NGL Prices to Continue Falling
With crude oil prices likely to continue to push lower and U.S. LPG export economics continuing to flash negative, the path of least resistance seems to be lower for U.S. prices. Internationally, recent LPG gains on naphtha in Europe and Asia come at the expense of less attractive petrochemical feedstock margins. LPG's discount to the refined product will need to widen for higher consumption to occur.

Ethanol Output Reaches All-time High
U.S. ethanol production soared to a record 988 MB/D the week ending December 5, up 26 MB/D from the previous week. Stocks built by 461 thousand barrels to a seven-week high 17.75 million barrels.

The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA's current analysis of energy markets around the world as well as the key economic and political factors driving those markets.

BG Group has delivered first gas from its Starfish field in the East Coast Marine Area of Trinidad with the start-up of the first well in the program. This production will ensure a reliable flow of gas to the domestic market and to the Atlantic LNG export facility, a key source for the company's global LNG business.

Garvin Goddard, President of BG Trinidad & Tobago commented, "With Starfish coming on stream in our 25th year of operating in the country, this is a great demonstration of our ongoing commitment to the safe and responsible development of natural gas resources. Starfish also shows our capability to deliver complex offshore projects. We look forward to our next period of growth and continuing our contribution to the economy of the country."

Located around 50 miles offshore, the field is connected to the 3,000 ton Dolphin platform. The Starfish project was sanctioned in 2012 and has involved ongoing collaboration with local and international contractors. BG Group operates the East Coast Marine Area with a 50% equity interest. Our joint venture partner Chevron Trinidad and Tobago Resources SRL holds the other 50% equity interest. We also have interests across the four Atlantic LNG trains in Trinidad. Our global LNG portfolio receives cargoes from trains 2, 3 and 4.

Leading classification society ClassNK (Chairman and President: Noboru Ueda) has granted approval to the design of the new 28AHX-DF dual-fuel engine developed by Niigata Power Systems Co., Ltd. The new engine is slated to be used as the main engine on a new LNG-fueled tugboat being built by Keihin Dock Co., Ltd. for NYK Line. The vessel will be Japan's first LNG fueled vessel, excluding LNG carriers.

New regulations for Emission Control Areas (ECA), including new stricter limits on sulfur emissions as well as the IMO's Tier III NOx emission limits, are driving demand for new engine and emission control technologies. The high costs associated with low sulfur fuels, and the increasing availability of LNG is driving both vessel owners and machinery manufacturers to consider the use of LNG as a vessel fuel.

Niigata's 28AHX-DF is a medium-speed duel-fuel engine with a maximum rated power per cylinder of 320kW and was developed for use primarily in offshore support vessels and tugboats. The engine, which operates on both diesel fuel and LNG, will meet the strict 0.1% sulfur emissions regulations in the ECA that are set to go into effect in 2015, as well as comply with the IMO's stringent Tier III NOx emission requirements. Technologies used in the new engine were developed with the support of Japan's Ministry of Land, Infrastructure, Transportation & Tourism (MLIT), as well as ClassNK as part of the society's Joint R&D for Industry Program.

Mr. Yukihisa Shibata, General Manager of ClassNK's Machinery Department said: "The demand for dual-fuel engines is increasing as IMO restrictions tighten and the industry recognizes the importance of environmental accountability. Supporting the development of such low-emission engines is one way we can help ship operators and manufacturers practically address the challenges of these new regulations, and encourage the wide spread use of this new technology

Shin Yang Shipyard of Miri, Sarawak, Malaysia has delivered the sister ships MV Anis and MV Alya (photo). Designed by Wartsila Ship Design Singapore, the 83.8-meter (275-foot) maintenance and work boats have massive capacities.

Photos courtesy of Cummins Malaysia

Accommodation is provided for up to 199 people. Tankage is provided for 800 cubic meters of fuel and 900 m3 of water. The vessels each have two 50 m3 per day water-makers. Additionally there is tankage for 80 m3 of urea, 20 m3 of sludge, and 10 m3 of lube oil. There is 700 square meters of open deck cargo space.

For propulsion, each vessel is fitted with a pair of Cummins QSK60M engines each delivering 2200 HP at 1800 RPM. The engines turn four-blade 2000-m/m fix-pitch propellers through Twin Disc MG5600 marine gears with 5.04:1 rations.

Main gensets are three Cat-powered 590eKW, 50 HZ each. The emergency genset is a Cummins NTA855D(M) powered and rated at 245eKW. The ABS-classed vessel is equipped with a ten-ton electric drive bow thruster as well as three 75 cubic meters per hour at a 70-meter head fire pumps. To aid in her offshore work there is a 45-ton deck pedestal mounted deck crane. The Anis and Alya are also fitted with 50-ton four-point mooring systems.

Short-term investment models for shale make it more vulnerable to project cuts

With oil prices plummeting to a five year low, and project cut backs likely in 2015, short-term funding for US shale may lose out to the country's higher cost deep water developments, the latest article by leading petroleum industry advisor Gaffney, Cline and Associates (GCA) suggests.

The current low price of oil has been blamed on reduced demand and a global oversupply. Much of that oversupply is due to the huge increase in oil production from the US unconventional or shale industry.

New analysis from GCA indicates that where companies have the flexibility to choose, shale activity will most logically suffer first as a result of the price crash, leaving activity in other areas such as the Gulf of Mexico relatively more protected. However actual cuts will be influenced by a large number of individual company factors, and the squeeze on cash flow will undoubtedly cause cuts to be felt everywhere.

"Whilst high cost environments such as the deep water Gulf of Mexico would appear to be vulnerable, and undeniably cuts should be expected there, economic rationality suggests that the brunt of cuts should be directed at onshore unconventional investments. However, in the short term there is not always the operational flexibility to make decisions based solely on fundamentals," says the article's author Bob George, Executive Director and Senior Strategic Advisor at GCA.

Another key difference for deep "water projects is their longer-term investment lifecycle. In the Gulf of Mexico (GoM) for example, where a company's investment in a typical project may be US$1 billion or more, much or all of the investment will be committed and spent around five years before any returns are seen. The critical point for such projects is not the price of oil now, but its anticipated price in the future and where deferral in the short term may result in missed gains later.

"From a decision-making perspective, this means the risk lies in the expected price of oil in 2020. As a result, projects currently underway are less likely to be stopped. This is in contrast to onshore unconventional shale investment where decisions are often much more short term," says George.

"Shale drilling can be cut back or ramped up in fairly short order to accommodate the market conditions, resulting in more rapid response to fluctuating oil price."

At the end of October 2014 GCA posted an article* looking at the potential impact of US$80 per barrel on activity in unconventional shale oil plays in the United States. The article indicated that, using the "sweet spot" volatile oil window of the Eagle Ford as an example, activity was still profitable at that price although more fringe areas (and other basins with pricing disadvantages) might be more challenged. However, even the sweet spots in the Eagle Ford oil window started to look challenged at US$70 per barrel.

Co-authors Cecilia Jing Cui and Neil Abdalla point out that strong offshore GoM projects can still be viable down to US$60 per barrel. Economic rationality would suggest that where the opportunity exists, onshore shale spending would be a more appropriate short-term target for capital deferral because operating flexibility allows any adjustments made there to be reversed in equally quick order.

Bob George states, "Although pain is likely for areas like the offshore Gulf of Mexico in 2015, it should be much better placed to weather the storm of depressed oil prices in the short term than the US onshore unconventionals industry."

The ceremony for this important achievement was held in Luanda, in the presence of the Minister of Petroleum of Angola and the top management of Eni and Sonangol

Eni has started production of first oil from the West Hub Development Project in Block 15/06 in the Angolan Deep Offshore, approximately 350 kilometers northwest of Luanda and 130 kilometers west of Soyo. The field is currently producing 45,000 barrels of oil per day (bopd) through the N'Goma FPSO, with production ramp-up expected to reach a daily production of up to 100,000 bopd in the coming months. The start-up of the East Hub Development, expected in 2017, will raise overall production from Block 15/06 to 200,000 bpd.

N'Goma FPSO Credit: SBM Offshore

The development project started with a very successful exploration campaign. Having won the international bid round in 2006, in Block 15/06 Eni drilled 24 exploration and appraisal wells, discovering over 3 billion barrels of oil in place and 850 million barrels of reserves. The discoveries were then developed quickly and efficiently, achieving an industry-leading time to market of only 44 months from the Declaration of Commercial Discovery thanks to the application of a new modular development model. Indeed, the West Hub Development entails the sequential start-up of the Sangos, Cinguvu, Mpungi, Mpungi North Area, Vandumbu e Ochigufu fields.

Eni will also continue its exploration program in Block 15/06: potential discoveries tied in quickly and cost efficiently. A recent example is the Ochigufu discovery, which added 300 million barrels of oil in place and which will be tied in to the N'Goma FPSO within the next two years.

Eni CEO Claudio Descalzi commented: "The start-up of the West Hub in Angola is a milestone in Eni's upstream activities. Starting from an extraordinary exploration success we have achieved an industry-leading time to market of only 4 years from the declaration of commercial discovery. This result reflects a new, modular, development model which adds value to our strategy of organic growth. The start up of the West Hub is also significant in terms of Eni's presence in Angola, where are again Operator of a major producing project'.

This significant achievement is celebrated today in Luanda at a ceremony attended by the Angolan Minister of Petroleum, José Maria Botelho De Vasconcelos, Eni's Ceo, Claudio Desclazi, President of Sonangol, Francisco de Lemos José Maria, Angolan Oil & Gas industry representatives, and members of Eni's management.

Eni is operator of the Block 15/06 with a 35% stake and Sonangol EP is the Concessionaire. The other partners of the joint venture are Sonangol Pesquisa e Produção (35%), SSI Fifteen Limited (25%) and Falcon Oil Holding Angola SA (5%).

Angola is a key country in the strategy of organic growth of Eni, which has been present in the Country since 1980 with a daily production in 2013 of 87,000 barrels of oil equivalent.

Ranger Offshore, Inc., a leading global marine and subsea construction and support services contractor to the offshore oil and gas industry has closed the previously announced agreement to acquire Technip USA's diving assets.

Highlights:
• Strategic acquisition – supporting Ranger's next phase of growth, including:
◦ Multi-year preferred sub-contractor agreement to provide diving services to Technip USA
◦ Further capacity to deploy additional diving spreads and broaden its growing customer base in existing markets
◦ Expansion into key new markets in Africa and South East Asia

• Assets include:
◦ Two multi-service support vessels - The MSV Global Orion and The MSV Normand Commander
◦ Saturation diving systems, a hyperbaric receiving facility, surface compression chambers, launch and recovery systems, diving control systems and other ancillary diving equipment
◦ Staff, including divers, supervisors and shore based support and project management teams that have a strong track record of operational excellence

The assets have established accreditation and decades of proven performance, along with best-in-class diving procedures that meet the strict standards of major oil companies, large independents, and top tier contractors.

Bill Lam, CEO of Ranger commented,
"This acquisition gives Ranger additional critical capacity to enhance our service offerings, grow with and serve our existing customers, and capture new business opportunities. In particular, we are now well-positioned to execute our strategic plan to grow into key global regions such as Africa and Southeast Asia, where current market demand for our services far outpaces existing qualified capacity.

We have already made significant advances in preparing and managing the integration of these assets into the wider Ranger Group and, with the acquisition closing on schedule, we look forward to continuing with the next phases of our growth plan."

The Company was advised by Pareto Securities on this transaction. Pareto Securities is an independent full service investment bank headquartered in Oslo, with more than 350 employees located in offices throughout Scandinavia and in Houston, New York, London, Calgary, Singapore, Rio de Janeiro and Perth, Australia. Pareto Securities has a leading position within the international energy sectors and is actively providing M&A advice and capital markets services to companies globally.

Trond Rokholt and Torjus Berge, Managing Directors in the Houston office of Pareto Securities said, "We were delighted to support the team at Ranger in advising on this transaction and financing. The successful completion of the acquisition of assets from Technip will form the basis of the company's next stage of growth. In particular it will support development into new but known international markets, where an evident demand supply gap exists."

NYC-based PIRA Energy Group reports that crude prices fall as Cushing stocks rise. In the U.S., stocks drew slightly. In Japan, crude runs rose, crude imports were lower and crude stocks drew. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

Crude Prices Fall as Cushing Stocks Rise
Crude prices continued their downward spiral in November, with WTI dropping below $70/Bbl. Regional grades in the Rockies and West Texas strengthened vs. WTI, on new pipeline takeaway capacity. Canadian crude differentials weakened slightly. Cushing crude stocks rose 3 million barrels in November, ending the month at 24 MMB.

U.S. Stocks Draw Slightly
This past week crude runs soared to the highest level since peak summer runs. This ended nine weeks of product stock declines during the fall maintenance season, and product inventories increased. Not surprisingly, crude stocks flipped to a draw from mostly builds. The resulting overall stock decline was 6 million barrels less than last year's inventory decline for the same week, widening the year on year inventory excess.

Japanese Crude Runs Rose, Crude Imports Were Lower and Crude Stocks Drew
Crude runs rose out of turnarounds. Alignment with our planned turnaround schedules still looks good. Crude imports were lower and crude stocks drew 2.1 MMBbls. Finished product stocks drew due to draws on fuel oil and naphtha. Gasoline demand was slightly higher, the yield increased and stocks built. Gasoil demand was lower, and stocks drew. Kerosene demand fell and stocks built.

PADD Crude Balances Show Different Reactions to Production Growth
By now, the story about the increase in U.S. crude production and the resulting decline in crude net imports is a familiar one. How these changes played out in individual PADDs, however, is a different story. Parts of each regional crude balance have followed quite a different path than the national aggregation. Changes to internal logistics and flows are a key part of the story, with rail both contributing to, and benefiting from, the growth in shale crude production. A prolonged period of low prices, especially low wellhead values in the Bakken and Canada, could dramatically reduce the need for infrastructure growth, and slack infrastructure utilization would be reflected in additional narrowing of regional price differences.

Freight Market Outlook
OPEC's decision to leave their production target unchanged at current levels signals the start of a new era for the oil markets. While the oil sector is now in crisis mode, the tanker sector is experiencing a seasonal rebound. Bunker prices have declined by more than $185/ton since July while tanker rates have generally firmed in most trades, leading to sharply higher vessel earnings. The new normal seems to be characterized by more frequent tanker rate spikes and higher volatility in the Atlantic Basin as trading patterns have yet to fully adjust to the growing volumes of crude and products that must move from the Atlantic to Asia. Longer term, higher OPEC output, lower growth in non-OPEC supplies and inexpensive bunker fuel are highly beneficial to the tanker sector.

U.S. NGL Prices Crushed
It's becoming increasingly clear that LPG supply is outpacing demand globally. While crude prices have stabilized for the moment, LPG has had no such luck, with prices remaining in freefall mode. U.S. prices were crushed across the board, with the Saudi CP cut a major catalyst; Mont Belvieu propane fell 15% to 58¢/gal and butane lost 17% to 81¢. But the ethane price deterioration was even worse. C2 prices fell a massive 23% as the feedstock struggles to compete with cheap propane in the U.S. steam cracker pool.

Ethanol Manufacturing Margins Soar
U.S. ethanol assessments were mixed during the holiday-shortened week ending November 28; prices in Chicago and the Gulf Coast continued to climb as the market was tight, while New York and Southern California ethanol tumbled from lofty levels. Manufacturing margins were the highest since March as inventories remained low.

Ethanol Stocks Build
U.S. ethanol manufacture declined to 962 MB/D during the holiday-shortened week ending November 28, down from a record 982 MB/D in the preceding week. After falling for two consecutive weeks despite record output, stocks built by 217 thousand barrels to 17.3 million barrels.

The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA's current analysis of energy markets around the world as well as the key economic and political factors driving those markets.