Schlumberger: Schorn Speaks at Cowen & Company Energy & Natural Resources Conference




Schlumberger: Patrick Schorn Speaks at Cowen & Company Energy & Natural Resources Conference

Ladies and gentlemen good morning. My thanks to Marc Bianchi and Cowen & Company for the opportunity to be here once again.

The dramatic downturn that we have seen during the last three years has meant that our industry has had to change. And while the pressure on service pricing has been severe, new technologies, integrated service offerings, and digital enablement have played an increasing part in lowering cost per barrel. The downturn has of course led to cost cutting, headcount reduction, and weaker financial performance, but it has also presented opportunities for transformation, reorganization, and new ways of working.

With signs of recovery now emerging as producers either work within available cash flow, or limit production more closely, I’m going to use my time today to show what this means for Schlumberger.

I have three topics to present before commenting on how we see the fourth quarter.

The first is technology, where I’ll show how transformation of our engineering and manufacturing processes has led to new generations of more reliable and more efficient field equipment to increase production and lower cost per barrel.

Second, I’ll discuss how scale and vertical integration are streamlining operational processes and workflows in the completions and production market to improve technical and financial performance.

And third, I’ll describe how technology systems are becoming increasingly digitally enabled to introduce new ways of working across E&P workflows to deliver a step change in behavior.

But before I begin with our view on the industry macro, let’s get the formalities out of the way.

Some of the statements I will be making today are forward-looking. These matters involve risks and uncertainties that could cause our results to differ materially from those projected in these statements. I therefore refer you to our latest 10-K filing and our other SEC filings.

When we look at the change in market fundamentals since the end of 2014, we see a number of things. Most importantly, global E&P capital spending has fallen from a high of about $700 billion in 2014 to less than $400 billion in 2016, driven by the precipitous fall in the price of oil. Brent, for example, has plummeted from $120 per barrel in 2013 to levels that demonstrated stability around $50 per barrel before rising above $60 level today. Upstream job losses have reached 440,000 or more, and the number of bankruptcies in the industry has topped 300. But in spite of this, production of crude oil and associated petroleum liquids has grown from 92 to 98 million barrels per day since 2013 showing little reflection of the dramatic drop in E&P investment.

But more importantly, the demand for oil continues to be strong with upward growth revisions in many areas, including the OECD. Growth in 2018 is expected to exceed 1.4 million barrels per day, supported by global GDP figures that clearly suggest that the demand for oil is solid. The 2018 IEA World Energy New Policies baseline scenario supports this view with forecasted annual demand of 105 million barrels of oil per day by 2040. An increasing percentage of this will have to come from new developments to replace production lost to decline.

One of the major factors driving the dramatic change of the past three years has been the rapid growth in production of light tight oil from unconventional reservoirs on land in the US. This has revolutionized supply, but signs of its limitations are beginning to emerge.

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SeaBird Exploration: Approved prospectus and commencement of subsequent offering




SeaBird Exploration: Approved prospectus and commencement of subsequent offering


Reference is made to the stock exchange release from SeaBird Exploration PLC (“SeaBird” or the “Company”) published on 15 September 2017 regarding the successful completion of a private placement of 1,000,000,000 new shares in the Company (the “Private Placement”) and a potential subsequent repair offering of up to 50,000,000 new shares in the Company (the “Subsequent Offering”).

The Norwegian Financial Supervisory Authority has approved the prospectus of the Company dated 4 December 2017 (the “Prospectus”) related to the Private Placement and the Subsequent Offering and listing of up to 50,000,000 new shares (the “Offer Shares”), each with a par value of NOK 0.001.

The Prospectus can be obtained electronically by downloading it from, and, or by contacting ABG Sundal Collier or Arctic Securities (the “Managers”).

In the Subsequent Offering, the Company will, subject to applicable securities laws, grant rights to subscribe for Offer Shares to shareholders in the Company as of close of trading on 15 September 2017 as registered in the Norwegian Central Securities Depository (the “VPS”) on 19 September 2017 (the “Record Date”) who were not contacted with respect to the Private Placement, and who are not resident in a jurisdiction where such offering would be unlawful or (for jurisdictions other than Norway) would require any prospectus, filing, registration or similar action (“Eligible Shareholders”).

The Offer Shares are not listed and tradeable shares. The Offer Shares will be converted to ordinary shares, transferred to the ordinary ISIN of the Company’s shares and become tradeable on Oslo Børs under the trading symbol “SBX” upon publication of this Prospectus and a subsequent capital reduction relating to the reduction of the nominal value of the Company’s ordinary shares having been completed by the resolution of a competent court in Cyprus.

The subscription period in the Subsequent Offering commences on 5 December 2017 at 09:00 CET and will end on 19 December 2017 at 16:30 CET (the “Subscription Period”). The subscription price in the Subsequent Offering is NOK 0.10 per Offer Share, which is the equal to the subscription price in the Private Placement.

Eligible Shareholders will be granted 1.51 Subscription Rights for each share held. Each Subscription Right will give the right to subscribe for one (1) Offer Share. The Subscription Rights will not be tradable or listed on the Oslo Stock Exchange. Oversubscription is permitted.

In order to subscribe for shares, one of the Managers must receive a complete and duly signed subscription form within the end of the Subscription Period. Further instructions regarding the subscription procedure is available in the Prospectus. Subscription Rights not used to subscribe for Offer Shares prior to 16:30 CET on 19 December 2017 will lapse without compensations to the holder and consequently be of no value.

Notifications of allocation in the Subsequent Offering are expected to be issued on or about 20 December 2017. The due date for payment of allocated Offer Shares is 27 December 2017 (the “Payment Due Date”). Delivery of the Offer Shares to investors’ VPS accounts is expected to take place on or about 29 December 2017.

ABG Sundal Collier and Arctic Securities acted as joint bookrunners in the Private Placement and the Subsequent Offering. Advokatfirmaet Schjødt AS acted as Norwegian legal counsel to the Company.


PGS: MultiClient Day – Oslo




PGS: MultiClient Day – Oslo

PGS is hosting a half-day MultiClient Norway seminar on the morning of Tuesday, 5th December at the PGS head office in Oslo.

Start your day with a preview of GeoStreamer data on the Norwegian Continental Shelf and an insight into our upcoming plans and new technology.

Enjoy a series of interactive data sessions exploring new prospectivity and exploration targets throughout the shelf, in addition to topical talks from external speakers.

This seminar is suitable for E&P companies: exploration managers, geologists, geophysicists and geoscientists.

Date: 5 December 2017

Time: 08:30-13:00 (lunch included)

Location: PGS House, Lilleakerveien 4c, Lysaker


Fugro: 3rd Ground investigation awarded on Scotlands A9 Dualling Programme





Fugro: 3rd Ground investigation awarded on Scotlands A9 Dualling Programme

Fugro will be mobilising full ground investigation capabilities in the Scottish Highlands as it makes a winter start on its third contract for Transport Scotland on the Scottish Government’s ambitious A9 dualling programme.

The £1.3 million award includes integrated geotechnical and geophysical data collection along 23 kilometres of road corridor to inform the design work for two sections of dualling – Glen Garry to Dalwhinnie and Dalwhinnie to Crubenmore.

Due to start mid-December, the 26-week contract marks a return to challenging highland terrain within the project’s central section through the Cairngorms. A 12-week programme of site work will include 48 rotary boreholes to undertake 290 metres of coring and 334 metres of open hole drilling, plus a further seven sonic boreholes for soil and rock coring to over 70 metres in depth. Fugro will also undertake almost 100 machine dug trial pits, geotechnical soil and rock testing, contamination testing, peat probing, wireline geophysics, surface geophysics, post fieldwork monitoring and reporting.

Geophysicists and geotechnical engineers from Fugro, a global leader in geo-intelligence and asset integrity solutions, will be working closely to deliver the required data safely and efficiently to help Transport Scotland meet the dualling construction schedule.

Neale Davies, Fugro’s Estimating Manager, said, “Fugro is delighted to have been awarded a third ground investigation on this prestigious project through some of Scotland’s most picturesque mountain scenery. We look forward to continuing our close work with Transport Scotland and their engineer, CH2M Fairhurst Joint Venture, in order to meet, or even exceed, their expectations.”

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Boskalis: Share Buyback Update




Boskalis: Share Buyback Update

In the period from 27 November up to and including 1 December, Royal Boskalis Westminster N.V. (Boskalis) repurchased own shares. The repurchases took place within the framework of the share buyback program announced on 3 July 2017.

Click here for a complete overview of all individual transactions.

Boskalis will publish a press release every Monday for the duration of the buyback program, provided shares were repurchased in the preceding week. Interested parties can subscribe to these press releases at  An overview of the progress of the program can be found on


CGG: Announces the launch of CEO succession plan




CGG: Announces the launch of CEO succession plan

With the favorable decision of the Paris Commercial court approving the safeguard plan further to the approval of the resolutions necessary to implement the plan by the extraordinary general meeting and the confirmation judgement for the Chapter 11 in the United States, the next procedural step of CGG’s financial restructuring, before implementing its financial restructuring plan which should be completed in Q1 2018, is the hearing scheduled on December 21, 2017 to consider the motion for the recognition of the ruling approving the safeguard plan within the context of the Chapter 15 proceedings.

As CGG is now moving towards a new stage, and after 8 years as Chief Executive Officer of CGG, Jean-Georges Malcor has decided, in agreement with the Board of Directors, not to pursue his mandate of Chief Executive Officer once the restructuring process is completed.

The Board of Directors will therefore immediately launch the search for a new Chief Executive Officer.

Jean-Georges Malcor will complete the financial restructuring process in the first quarter of 2018. He will then step down as Chief Executive Officer when his successor is appointed. Jean-Georges Malcor will remain in the company until his retirement on October 1st, 2018 in order to support him/her in taking office.


ION Geo: nearly quadruples 2D multi-client data offshore Argentina




ION Geo: nearly quadruples 2D multi-client data offshore Argentina

ION Geophysical Corporation (NYSE: IO) today announced it is offering a 2D multi-client data package offshore Argentina in advance of the 2018 license round.  ION has delivered a regional framework consisting of approximately 30,000 km of data over the Austral and Malvinas basins’ relatively under-explored petroleum region.  For almost 10 years, ION’s 11,500 km of ArgentineSPAN was the only dataset available in the Argentine offshore.  The knowledge gained from working these data enabled us to confidently incorporate and interpret the 30,000 km of vintage data into our extensive regional understanding offshore Argentina.  ION secured the seismic data and well reports with exclusive licensing rights.

ION will provide a full interpretation report detailing the exploration history, the geologic framework and an inventory of potential leads to jumpstart exploration efforts there in advance of the anticipated license round in 2018.  The complete seismic database is available now and the full interpretation report will be completed in December 2017.

Joe Gagliardi, SVP of ION’s Ventures group, said, “ION continues to be a leader in frontier exploration and fit-for-purpose solutions.  Acquiring access to this unique dataset has provided the opportunity for ION to get information into the hands of our clients at an early stage, which can be used for both acreage evaluation and assessment if other data is necessary for operators to build and execute a rapid evaluation strategy for the region in advance of the license round.”

Link     ION Agrentina

Europa Oil & Gas: Sale of Block 41/24 (P2304)




Europa Oil & Gas: Sale of Block 41/24 (P2304)

Europa Oil & Gas (Holdings) has sold its 50% interest in Promote Licence P2304 (UKCS Block 41/24) to Egdon Resources. Europa’s joint venture partner Arenite Petroleum has also sold its 50% interest to Egdon as part of the same transaction.

P2304 is located to the immediate south of Egdon’s 100% owned licence P1929 (UKCS Blocks 41/18 and 41/19) offshore North Yorkshire.

The consideration comprises the immediate reimbursement of the 2017 licence rental, OGA Levy and vendors’ legal costs (c. £15,000 in total) and future staged payments that have the potential to total £1.45m gross contingent consideration on the successful completion of various potential exploration activities and/or on reaching certain production milestones.

Europa chief executive Hugh Mackay said: ‘The sale of our interest in P2304 eliminates our exposure to ongoing costs whilst retaining our exposure to future drilling success. ‘Furthermore, combining P2304 with Egdon’s licence is anticipated to enhance the possibility of delivering farmout success to the benefit of all parties to the transaction. ‘Today’s disposal is in line with our strategy to optimise the risk / reward trade off across our onshore UK and offshore Ireland exploration portfolio. ‘We continue to focus on securing farm outs, specifically within our industry leading portfolio of offshore Ireland licences, and I look forward to providing further updates in due course.’


Thalassa Holdings: Share Buy Back update




Thalassa Holdings: Share Buy Back update

The board of Thalassa announces that on 1 December 2017 the Company purchased 208,250 of its shares at a price of £1.05 per share. These shares will be held in treasury and in total there are now 5,164,882 shares in treasury. This purchase was made in accordance with the Company’s Articles of Association and with a board authority dated 12 July 2017 to buy back up to £4,000,000 of the Company’s shares. As at the date hereof, the Company has purchased 2,056,225 shares under this authority for a total cost of £1,772,817 or an average price of 86.22 pence per share. The average purchase price of the total number of shares held in treasury is 60.39 pence per share for a cost of £3,119,256.


The Company advises that, following this purchase, the Company’s issued share capital remains at 25,567,522. The total number of shares with voting rights is now 20,402,640. This figure represents the total voting rights in the Company and may be used by shareholders as the denominator for the calculations by which they can determine if they are required to notify their interest in, or a change to their interest in, the Company in compliance with Thalassa’s Articles of Association.


Egypt: Igniting the Red Sea Hydrocarbon Potential




Egypt: Igniting the Red Sea Hydrocarbon Potential

Geologists consider the Red Sea as one of the world’s most promising areas for hydrocarbon exploration. There are nine countries that border the Red Sea: Saudi Arabia, Egypt, Yemen, Israel, Jordan, Djibouti, Eritrea, Somalia, and Sudan. Some of these countries, mainly Saudi Arabia and Sudan, started exploration activates in the area years ago.

Following the recent bilateral maritime-demarcation agreement signed with Saudi Arabia, Egypt is finally able to begin exploring its Red Sea waters, beyond the Gulf of Suez. The Red Sea offers exciting opportunities for potential stakeholders. The United States Geological Survey (USGS), using a geology-based assessment methodology, estimated in 2010 that the Red Sea Basin Province contains a mean volume of 5 billion barrels of undiscovered technically recoverable oil and 112 trillion cubic feet (tcf) of recoverable natural gas.

Egypt on Track 

After many years of limiting eastern offshore exploration and production (E&P) activates in the Gulf of Suez, in April 2016 both countries inked the bilateral agreement, allowing Egypt to announce exploration plans for the Red Sea, which took place in July 2017, one month after the ratification of the maritime-border-demarcation agreement.

“The agreement allowed Egypt to start its exploring activities in this area of the Red Sea, since it determined Egypt’s limits in exploring oil,” the Minister of Petroleum and Mineral Resources, Tarek El Molla, said in an official statement; further noting that there are two similar maritime-demarcation agreements currently under negotiation with Greece and Cyprus.

With the new demarcation agreement in place, state-owned South Valley Egyptian Petroleum Holding Company (Ganope), signed contracts worth $750 million with Schumberger and TGS. Under the terms of the contracts, the companies began collecting geo-science data from Egyptian territorial waters in the Red Sea in preparation for E&P activities. After finalization of the project, the ministry will be prepared to receive bids for oil and gas exploration in Egypt’s territorial waters in the Red Sea and southern Egypt, according to Ahram Online. “The survey will be limited between 22° and 28° in [the] Red Sea, to cover 55 km²,” El Molla specified, according to Egypt Today.

Noting the importance of the seismic survey agreement, Tamer El Daker, an Exploration Manager at Dragon Oil, stated that “the new seismic technology used will help a lot in collecting new data to attract oil companies to start exploring in the Red Sea. Egypt did [not] have the chance to do that before due to some financial problems, while Saudi Arabia did a lot of successful exploration [on its] side of the Red Sea.”

When asked about the cause of the delay, Mohamed Ghanim, a senior geologist, noted that the agreement for delineating the marine border between Saudi Arabia and Egypt was only finalized in 2017—much later than Saudi Arabia’s agreement with Sudan.  Aziz Abd El Salam, Senior Exploration Geologist at Badr Petroleum Company (Bapetco), countered, however, that the attention to oil and gas discoveries in the Western Desert and GOS areas are the main reason for the Egypt’s delay in exploring the Red Sea.

While views vary on why exploration has been delayed, not everyone even agrees that a delay has occurred. “I don’t think there is any delay from Egypt to explore oil and gas in the Red Sea,” Dr. Maher H. Ayyad, Professor of Petroleum Geosciences at Cairo University, said. He noted that areas both in and near the Red Sea have been explored “with modest success” for a long time. Affirming Ayyad’s opinion, Ahmed Shohdy, Development and Operation Geologist at Saudi Aramco, noted that exploration of the Red Sea has not been delayed, however, due to geological factors, exploration and development was easier within Saudi Arabian territory due to the presence of source and reservoir rocks in shallow water. Sudan, he noted, is currently exploring shallow water locations and has already discovered a delta-shaped structure, encouraging additional exploration despite current low production rates.

Promising Potential

Egypt’s Ministry of Petroleum and Mineral Resources has not stated whether Egypt’s exploration of the Red Sea will extend beyond the 55 square kilometers contained between the 22° and 28° boundaries mentioned by the minster. Ghanim believes the exploration could extend beyond this area. If the initial surveys indicate a high potential for discoveries, exploration activities “should cover all the Red Sea because the geological setting is very similar,” he said.

Giving an in-depth comparison, Ayyad explained that “in [the] early 1950s, the GOS was considered as [an] exploration heaven in Egypt where giant oil and gas fields started to be uncovered. The Red Sea, on the other hand, is quite different from the GOS in many aspects […] This, however, does not mean that the Red Sea [has] less potential than the GOS. It is still way under explored and requires huge efforts—financially, technically, and logistically—to prove itself a viable replacement to or extension of the GOS operations.”

Since 1974, a total of 28,350 km of 2D seismic data and 4,360 km of 3D seismic data has been collected and 12 test wells have been drilled in various concessions in the GOS area. The heavily explored area and the natural oil seeps surrounding the Red Sea prove a working multi-petroleum system at the northern and southern ends of the Red Sea Province with a syn-rift to post-rift petroleum system in between, according to Sherif Sousa, former CEO of Ganoub El-Wadi Petroleum Holding Company, according to Abdelghani Henni in an article about oil and gas in the Red Sea.

Furthermore, Ayyad noted that “the Red Sea area is divided into shallow-water ‘Pan-handle’ area to the north of Hurghada and the larger deep-water regional area to the south with a narrow strip of a shallow shelf along the coast. The area is generally characterized by a relatively higher Geothermal Gradient, which might have an effect on the Hydrocarbon System. In addition, the shallow areas in the north have been operated [in] by several oil companies including Mobil, Conoco, [and] GPC, with small oil and gas finds, such as undeveloped Hareed, Felfel.”

“Saudi Aramco was the first to use a deep-water rig in the Red Sea region after a 15-month seismic study in 2009 indicated the presence of natural gas. As a result, the company discovered three oil and two gas fields in 2013 and started developing the gas fields. However, work was halted in 2015 due to several factors, including environmental issues, costs, and the need for further studies to minimize risks,” according to Henni.

In 2016, Saudi Aramco awarded the Norwegian firm Magseis and BGP, a subsidiary of China National Petroleum Corporation (CNPC), to perform a 3D transitional-zone seismic exploration in the Red Sea. “We continue our program to explore the shallow waters of the Red Sea, completing our largest single survey of the seabed encompassing Saudi Arabian territorial waters,” Saudi Aramco stated in an annual report quoted by Henni. In May, Magseis announced the completion of the initial survey and began work on a contract extension. Saudi Aramco has yet to release any official estimates on the hydrocarbon potential in the Red Sea, curbing speculation that reserves under the seabed could amount to as much as 50 bb, according to The National. Many experts doubt that proven reserves will realize the 50 bb estimate.

In a similar action to Saudi Arabia’s, Sudan started drilling its first offshore exploration well in the Red Sea with the help of CNPC in 2010. The well is located in Area 15, which is operated by the Red Sea Petroleum Operating Company. The company is a consortium comprised of CNPC, Petronas, Sudapet, Express Petroleum, and High Tech Group. Petronas and CNPC each have a 35% interest in the block, according to Sudan Tribune.

Many geologists argue about whether Egypt can rely on Saudi and Sudanese reserve estimates in the Red Sea as a guide for predicting Egyptian reserves. “It should be considered because [the] geological setting is very close,” stated Ghanim.  Moreover, Ayyad explained that “In reference to Saudi Arabian and Sudanese potential reserves in the Red Sea and whether we rely on them, all I can say is that these finds represent [a] good sign that we have a vast basin with a hydrocarbon working system that needs much more investment.”

On the other hand, both Abd El Salam and Shody think that Egypt can use the potential Sudanese reserves, but not the Saudi Arabian ones, in the Red Sea to predict its own potential reserves. The Saudi Arabian reserves “may differ” but the Sudanese reserves “may be the same structure and stratigraphy” as Egyptian geological formations, stated Abd El Salam. Explaining why Egypt can’t rely on estimated potential reserves in Saudi Arabian waters, Shohdy said that “we can rely on Sudan’s potential since it could be considered in the same structural regime in the southern part of Egypt, but the potential is not as promising. While for [the] Saudi side, it could be considered as a different block with a rift action, such as the case of the Western Desert in Egypt and Sinai.”

Exploration Challenges

Although the Red Sea area is very promising, there are some challenges facing E&P activates in the area due to its rough seafloor topography; complicated geology under thick, salt deposits; and its pristine ecosystem. “It is [a] deepwater and remote area with little geological information” that will require the use of the “best experts” and technology to manage risk, Ghanim said.

Abd El Salam expressed a similar opinion, “the main challenges may be the reserves in the area.” Shohdy explained that the main deepwater challenges are the lack of source and reservoirs rocks, such as cretaceous deposits, and the salt problem, as it thick and movable. He further mentioned that expensive drilling costs in deepwater could prove the main challenge to E&P activities in the area.

With the average cost of a deepwater rig at approximately $600 million, drilling costs could be a serious deterrent. Saudi Arabia, which already has vast petroleum resources, has been slow to tap its Red Sea potential although the basin may be one of the last great exploration frontiers for the kingdom. Still, the Red Sea is on the government’s radar, according to Henni.

The main challenges confronting exploration activities in the seared Sea, Ayyad concludes, are “high Geothermal & Geo-pressure gradient, thick salt deposits that may cause drilling hazards; seismic data quality, particularly, beneath the salt, that require special processing techniques to enhance data quality; unexpected hazardous shallow gas pockets which require close attention while drilling; excessive deepwater render drilling very much costly; and distance from onshore facilities.”

After many years of overlooking it, Egypt—following Saudi Arabia and Sudan—has decided to unleash the oil and gas potential of the Red Sea. The ongoing seismic data collection is the first step in the exploration for oil and gas in the Red Sea. This road, however, despite its promise, holds significant technical, financial, and logistical challenges for E&P.