McDermott International, Inc. (NYSE: MDR) ("McDermott") is pleased to announce the successful completion of the Jack and St. Malo project for Chevron U.S.A. Inc. The project involved the installation of jumpers, flying leads, subsea pump stations, umbilicals and subsea landing of some of the industry's largest and complex umbilical end terminations to a host floating production platform in 7,200 feet of water 279 miles offshore Louisiana. The project is part of the first stage of development of the Jack South, St. Malo South and St. Malo North Drill Centers.

McDermott subsea construction vessel NO102 installed umbilicals totaling 65 miles along with other related subsea structures. (Photo: Business Wire)

McDermott executed in-house fabrication of 21 high specification rigid flowline, manifold and pump jumpers and installed the structures using the Derrick Barge 50 ("DB50") with its specialized deepwater lowering system. In addition, more than 80 flying leads, five additional rigid production well jumpers and other subsea control and production boost components were installed by the DB50 – including three pump stations each weighing 209 tons to a depth of 6,988 feet. The DB50 was assisted by a fleet of up to 12 support vessels delivering material from various Gulf Coast fabrication and staging facilities to the offshore installation site.

Additionally, three control and two power umbilicals totaling 65 miles were transported and installed by the subsea construction vessel North Ocean 102 ("NO102") along with other related subsea structures.

"Our ability to fabricate the jumpers in house and utilize the combined strengths of the DB50's deepwater lowering system and the high payload and top tension capacity of the NO102's 330-ton vertical lay system allowed McDermott to deliver an integrated subsea solution for our client on this complex deepwater project," said Tony Duncan, Executive Vice President Subsea. "As the industry moves into deeper water, McDermott continues to tailor its subsea engineering expertise, fabrication facilities, and global fleet of specialized vessels to meet the evolving technical needs of our clients."

Located in the Gulf of Mexico Walker Ridge Area, the Jack and St. Malo fields are jointly being developed with a host floating production unit.

Statoil has completed the Martin well in US Gulf of Mexico and the Dilolo well in the Kwanza basin in Angola.

Statoil announces a small discovery in its Martin prospect located in the Gulf of Mexico (GoM). Statoil does not consider this to be a commercial discovery. The well has been drilled efficiently and plug and abandonment operations (P&A) are now ongoing.
Once P&A operations are completed the Maersk Developer rig  (photo) will move to the impact Perseus prospect in De Soto Canyon (DC) 231.

Angola, Kwanza basin
The Dilolo-1 exploration well in block 39 offshore Angola in the Kwanza basin was drilled to its pre-salt target.

The first drilling operation in block 39 has now been completed. In this first well hydrocarbons were not encountered, but the operation did provide a valuable calibration for other prospects in the area.

Further studies are needed in order to fully understand the well results. The well is now in the process of being plugged and abandoned.

The Stena Carron drillship (photo-right) will soon move to block 38 to spud the exploration well Jacaré-1.The Angolan pre-salt is a frontier play where Statoil will participate in eight commitment wells across five blocks.

Other ongoing activities
Statoil is currently also drilling the Giligiliani well in block 2 in Tanzania and has recently spudded the Romeo prospect near the King Lear discovery in the Norwegian North Sea.

Statoil is also preparing for its 18-month drilling campaign on the east coast of Canada following up the Bay du Nord oil discovery.
The company is also participating in two more wells in the Kwanza basin in Angola. These are the Puma well in block 25 (operated by Total) and the Locosso well in block 22 (operated by Repsol).

In Brazil, the Repsol-operated Seat-2 well in block BM-C-33 in the Campos basin is currently being drill stem tested (DST) after encountering a pre-salt hydrocarbon-bearing section.

Ownership overview:
Statoil is the operator (42.5%) of Martin, and its partners include Nexen (25%) and LLOG (26%).
In Angola on block 39, Statoil is the operator (37.5%), and its partners include Total (7.5%), WRG (15%), Ecopetrol (10%) and Sonangol P&P (30%). 

In block 38 Statoil is the operator (45%), with WRG (15%), Ecopetrol (10%) and Sonangol P&P (30%) as partners*.
* The Ecopetrol farm-in is subject to approval by Sonangol E&P and the Angolan minister of petroleum.

Shell announced on Tuesday further exploration success in Malaysia with another gas discovery at the Shell-operated deep-water Marjoram-1 well.

"Our strategy to expand our heartland areas through technologically advanced exploration is delivering tangible success in deep-water in Malaysia," said Andrew Brown, Shell Upstream International Director.

"We have a long history in the region, and the addition of new natural gas resources this year ensures we are able to continue to provide cost-effective, reliable, cleaner energy options for the future."

The Marjoram-1 well is located 180 kilometres off the Malaysia coast in Block SK318, in 800 meters of water. Earlier this year, Shell announced the Rosmari-1 gas discovery, also in this block.

Block SK318 is operated by Shell with an 85% interest, with the remaining 15% held by PETRONAS Carigali Sdn Bhd.

The Bureau of Ocean Energy Management (BOEM) issued an Advanced Notice of Proposed Rulemaking (ANPR) on Risk Management, Financial Assurance, and Loss Prevention to seek public input as it considers modernizing its risk management program and bonding regulations for offshore oil and gas operations on the Outer Continental Shelf. This first step initiates a dialogue about BOEM’s existing regulations, which are approximately 20 years old and have not kept pace with offshore infrastructure developments, including deepwater operations, current industry practices, and the growing costs of decommissioning.

“We would like to work with industry and others to determine how to improve our regulatory regime to better align with the realities of aging offshore infrastructure, hazard risks, and increasing costs of decommissioning,” said BOEM acting Director Walter D. Cruickshank. “Today’s action is an important first step in initiating a dialogue on how to best enhance our risk management program to better match current practices, with the ultimate goal of ensuring that industry meets its decommissioning responsibilities and the burden of decommissioning a facility on the Outer Continental Shelf does not fall to taxpayers.”

Existing regulations require lessees on the Outer Continental Shelf to provide bonds or other alternative forms of financial assurance to cover current and future operations, such as decommissioning oil and gas infrastructure. Since the current bonding requirements were set nearly a quarter of a century ago, offshore operations have changed significantly, such as increased advancements in the scale and complexity of deepwater and subsea operations, and the costs of decommissioning have dramatically increased. In light of the infrastructure and operational changes, BOEM has recognized the need to update its requirements and develop a comprehensive program to assist in identifying, prioritizing, and managing the risks associated with industry activities on the Outer Continental Shelf.

BOEM is seeking stakeholder comments regarding various risk management and monitoring activities related to offshore energy development on the Outer Continental Shelf. The advanced notice of proposed rulemaking seeks comment on the bonding and financial assurance program for BOEM's offshore oil and gas program. The bureau is also accepting comments on the analogous bonding and financial assurance program for BOEM's offshore renewable energy and hard minerals programs. The notice also solicits comments on best practices to mitigate risks, as well as whether, or to what extent, the current forms of financial assurance are adequate and appropriate.

The Advanced Notice Proposed Rulemaking will be published in the Federal Register on Aug.19, 2014 and available for public viewing the day before. The ANPR includes a 60-day comment period which will close at midnight on Oct. 20, 2014. After the comment period closes, BOEM plans on continuing its outreach and hosting a workshop with stakeholders to have additional opportunities for discussion as it considers options for proposed regulations.

Due to overcapacity in their rig portfolio, Statoil will lay up the COSL Pioneer rig in the fourth quarter of 2014.
The rig is currently carrying out an assignment on the Visund field and is scheduled to complete this work at the end of September.

The COSL Pioneer drilling rig.
(Photo: Ole Jørgen Bratland)

"After a careful review of our drilling plan, we find it necessary to suspend COSL Pioneer for the time being," says rig procurement responsible Tore Aarreberg.

In the beginning of July Statoil also announced that the drilling rig Scarabeo 5 will be temporarily suspended. Scarabeo 5 will be taken out of operations at the end of September for the rest of the year.

"At the moment we have three rigs contracted from COSL Drilling Europe. Our offshore organisation enjoys excellent cooperation with the contractor's drilling teams, and COSL Pioneer has demonstrated consistent, high efficiency in drilling operations. We are in close dialogue with the contractor concerning how the suspension of the rig will be implemented in practice, and we continue to look forward to many years of cooperation with COSL on the Norwegian shelf," Aarreberg says.

The rig is contracted until 2016 and will be used for drilling and completion of production wells on the Norwegian continental shelf.
COSL Pioneer being taken out of operation for a shorter period will have no impact on Statoil's production targets or planned exploration activity on the Norwegian shelf. The company will still be drilling 20-25 exploration wells on the Norwegian shelf in 2014, where the company operates about two-thirds of all wells.

Noble Energy, Inc. (NYSE: NBL) has announced final well results at the Katmai exploration well and the Dantzler appraisal well in the deepwater Gulf of Mexico.

At Katmai, wireline logging data indicates a total of 154 net feet of crude oil pay was discovered in multiple reservoirs, including 117 net feet in Middle Miocene and 37 net feet in Lower Miocene reservoirs. The discovery well, located in Green Canyon 40, was drilled to a total depth of 27,900 feet in 2,100 feet of water. Total gross resources(1) at Katmai are now estimated at between 40 and 100 million barrels of oil equivalent, including 40 to 60 million barrels of oil equivalent discovered from this initial well. Additional exploration and appraisal drilling will be required to test the remaining upside potential.

The Dantzler-2 appraisal well, located in Mississippi Canyon 782, encountered 122 net feet of crude oil pay in two high-quality Miocene reservoirs. The well was drilled to a total depth of 18,210 feet in 6,600 feet of water. Gross resources(1) at Dantzler have increased to between 65 and 100 million barrels of oil equivalent. Dantzler has been incorporated into the Company's plans in the Rio Grande development area, which also includes discoveries at Big Bend and Troubadour. The Rio Grande development remains on schedule, with first production from Big Bend expected in the fourth quarter of 2015 and Dantzler in the first quarter of 2016.

Susan M. Cunningham, Senior Vice President, Gulf of Mexico, West Africa, and Frontier, said, "The results at Katmai and Dantzler highlight Noble Energy's successful deepwater Gulf of Mexico program, which will contribute significant production and cash flow growth in the coming years. What we discovered at Katmai represents another commercial discovery in the Miocene trend and de-risks nearby prospects in the Company's Aleutians area. Our appraisal program at Dantzler has exceeded our expectations and enhances the value of the development."

Noble Energy operates Katmai with a 50 percent working interest. Ridgewood Energy Corporation holds the remaining 50 percent working interest.

At Dantzler, the rig has started well completion operations on Dantzler-2 and will then complete the Dantzler-1 discovery well. Noble Energy operates Dantzler with a 45 percent working interest. Additional interest owners are entities managed by Ridgewood Energy Corporation (including ILX Holdings II, LLC a portfolio company of Riverstone Holdings, LLC) with 35 percent and W&T Energy VI, LLC (a wholly owned subsidiary of W&T Offshore Inc.) with 20 percent.

(1) Range of resource estimate based on 75th and 25th percentile probabilities

(Houston) ABS, the leading provider of classification services to the global offshore industry, continues to improve construction and integration timeliness with the completion of the Rowan Resolute ultra deepwater drillship. This newbuild, the second in a series for global offshore drilling contractor Rowan Companies, was built in the Hyundai Heavy Industries (HHI) yard in Ulsan, South Korea It joins sister ship Rowan Renaissance as the next high-specification drillship to earn ABS' Integrated Software Quality Management (ISQM) notation.

"Reliance on computer-controlled systems has increased. And verifying software programs - including their integration - is vital to safe and efficient operations," says ABS Chairman, President and CEO Christopher J. Wiernicki. "ABS identified software verification and integration as construction issues several years ago and developed ISQM to address these problems so the time to first production could be reduced."

ISQM represents a change in focus for classification societies that previously focused on the physical assets. ABS' ISQM notation is the first proven approach to providing a clear process for minimizing software-related risk throughout the life of an asset.

"No other class society has classed the drilling equipment and other essential marine equipment with a software notation that addresses software quality during construction, at delivery and into operations," says Paul Walters, ABS Manager.

Rowan Companies, a first mover among drilling contractors in applying a structured software quality management approach, is pleased with the process and has seen the results in the commissioning of the first ISQM drillship, Rowan Renaissance, which left the HHI yard early this year and began operating in late April.

"Following ISQM with the construction of the Rowan Renaissance paved the way so that the second drillship, Rowan Resolute,went even more smoothly," says Greg Lanier, Rowan Software Quality Manager. "Rowan was ahead of the pack in testing this approach and has seen very favorable results, which we expect to be passed on to our customers."

The experience gained by HHI places the yard in a unique position. "By working with ABS and Rowan Companies on this project, we have built up a knowledge base that allows us to offer experience with a new process that will benefit our other clients," says Sang-Sik Yoon, ISQM Team Leader, HHI.

HHI will follow the ISQM process in the construction of the remaining two drillships in the four-unit series.
About ABS

Founded in 1862, ABS is a leading international classification society devoted to promoting the security of life, property and the marine environment through the development and verification of standards for the design, construction and operational maintenance of marine-related facilities.

WASHINGTON, D.C., August 18, 2014 – Platts – Surging U.S. oil production is sending ripples through the crude oil market -- in prices, trade flows and the downstream, the International Energy Agency's (IEA) top oil official said Sunday on Platts Energy Week.

U.S. production is expected to reach 8.5 million barrels per day (b/d) this year and 9.3 million b/d in 2015, almost double 2008's output of 5 million b/d, said Antoine Halff, the head of the IEA's oil industry & markets division.

"On prices, the surge in production has really offset the production [loss] we've experienced in places like Libya, Iran, and so on," he said. "So that's why prices have not risen more than they have. They've been fairly stable, remarkably stable, given all the turmoil in the Middle East and elsewhere."

Crude oil that had been imported into the U.S. can now be imported by other countries, Halff said.

"There's been a tremendous remapping of the oil trade flows, if you like," he said. "And now Asia is supposed to really become the magnet for global crude traded internationally. That's a big change. China is now importing more crude than the U.S., for instance."

Downstream, new refineries under development in the U.S., increased refinery runs and the installation of more and more modern processing units, have resulted in a surge in output of U.S. product exports, Halff said.

"In U.S. refining, it's really been a revolution in a way," he said. "But these changes have taken place against a background of changes elsewhere as well for other reasons. Rapid growth in refining capacity in the Middle East, in India, in China, and so on."

Upstream, about 60% of the Organization of Petroleum Exporting Countries’ (OPEC) incremental capacity growth over the next five years is supposed to come from Iraq, the cartel's second-largest producer, according to the IEA. But that growth is "seriously at risk" because of the uncertainty and political strife in Iraq, Halff said.

"We have to wait and see," he said. "We took down our forecast of Iraqi production even before the surge in violence started earlier last month. So we've reduced our forecast of Iraqi production for the next five years by about half a million barrels."

The forecast does not take into account jihadist group Islamic State's campaign in Iraq, but "reflects other problems that Iraq has -- red tape, corruption, bottlenecks, lack of infrastructure, and so on," Halff said.

Should the expected Iraqi output not materialize, Saudi Arabia could step in, Halff said, but noted the country's current plans for capacity development likely won't result in higher net capacity for OPEC's largest producer, Halff said.

"What we've seen, our assessment of Saudi plans at this point, is that all the new capacity that will come online will essentially replace capacity that's being mothballed or that's being allowed to rest," he said. "But if Saudi chose to increase capacity, it would be able to do so."

While the IEA sees "some growth" in the United Arab Emirates, "elsewhere in OPEC we see problems," Halff said. "We see flat production growth. Or we see even declines in places like Algeria and Kuwait."

The "real game changer" has been oil production from shale reserves, starting with the U.S., Halff said.

"I think the shale revolution could not have happened anywhere else than in the U.S.," he said. "It's no accident that this happened in the U.S. Because the U.S. has a unique combination of assets, not only geological resources, but also business culture, enterprising spirit, infrastructure in place, a lot of technological know-how, skilled labor, the right environmental structure, the right investment climate. All these factors could not be found in the same combination in any other country.

"But there's nothing that prevents other countries now that the technology has been developed to adopt it and to try to replicate the success of the U.S.," he continued.

"Chief among them is Canada, of course," Halff said. "Mexico is a candidate. But [that would] probably be more in the next decade than in the next five years. We see a little bit of growth in the next five years. But not so much. We see more growth probably in Argentina, more growth in Russia and probably a little bit of growth in Australia towards the end of the decade."

The IEA sees U.S. crude oil production hitting a plateau over the next five to seven years, Halff said, adding that the surge in U.S. production is not going to be the answer to the world's energy needs.

"There's a need for investment in OPEC," he said. "There's a need for investment in the Middle East. So there's no room for complacency. This surge in production is phenomenal. It's a game-changer in many ways. But that doesn't mean that we don't need the traditional suppliers anymore. We need them very much."

Other Program Highlights

Also on the program, Katherine Hammack, the U.S. Army’s assistant secretary for installations, energy and environment, joined the program for an extended discussion on the dramatic transformation of the U.S. Army's energy consumption. View part 1 here and part 2 here.

During Sunday’s “Market Spotlight” segment, Platts Senior Managing Editor Richard Capuchino Jr. discussed the growing popularity of Vasconia, one of Colombia’s top-exported crude oil grades.

Platts Energy Week airs at 8 a.m. U.S. Eastern time Sunday mornings on WUSA9 in greater Washington, D.C., and in Houston on KUHT, a PBS affiliate, as well as on other PBS stations in cities throughout the U.S., including Anchorage, Billings, Houston, Juneau, Las Vegas, Minneapolis, San Francisco, Raleigh and Wichita. For online viewing, the program is accessible at www.plattstv.com.

The program features interviews with leading figures from government, industry, markets, think tanks and the financial community. Host Bill Loveless is an editorial director at Platts who brings 30 years of energy journalism experience to the anchor chair. The program also features veteran energy news editor and Platts Energy Week Senior Correspondent Chris Newkumet.

Platts Energy Week is produced by Platts, the world’s leading source of information and intelligence on energy and related commodities and a division of McGraw Hill Financial [NYSE: MHFI] and WUSA TV, the Washington, D.C., CBS affiliate and flagship television station of Gannett Company. [NYSE: GCI]. While the program is U.S. focused and produced in Washington, it reflects the global vantage point of Platts, whose correspondents are stationed in such major capitals as London, Dubai, Singapore, Tokyo and Moscow.

Guest booking for Platts Energy Week and related inquiries should be addressed to this email: This email address is being protected from spambots. You need JavaScript enabled to view it.. Additional information about Platts and the energy sector can be found at www.platts.com. 

Production is now underway from the Cardamom development, the second major deep-water facility Shell has brought online in the U.S. Gulf of Mexico this year, following the start-up of Mars B in February.

Oil from the Cardamom subsea development (100% Shell) is piped through Shell's Auger platform (photo). When at full production of 50,000 barrels of oil equivalent a day (boe/d), Auger's total production capacity will increase to 130,000 boe/d.

"Cardamom is a high-value addition to Shell's production at the Auger platform and is another example of our excellence in deep-water project delivery," said Marvin Odum, Shell Upstream Americas Director. "The work to extend the production life of our first deep-water tension-leg platform is impressive and involved advanced exploration and development technology. Our future opportunities in deep water mean that this will remain an important, high-return growth area for Shell."

Since its first production in 1994, the facility has received several upgrades to process additional production from new discoveries. Cardamom is Auger's seventh subsea development.

The Cardamom reservoir sits beneath thick layers of salt in rock more than four miles (6.4 kilometers) below the sea floor and went undetected by conventional seismic surveys. Shell used the latest advancements in seismic technology to discover Cardamom in 2010.

The Cardamom field is 225 miles (362 kilometres) south-west of New Orleans, Louisiana, in water more than 2,700 feet (820 metres) deep.

Other deep-water Gulf of Mexico growth for Shell includes the Mars B (Shell 71.5%) development, which continues to ramp up production; the ultra-deep-water Stones (Shell 100%, 50,000 boe/d) project, which is under construction; front-end engineering and design is progressing for the Appomattox (Shell 80%) project; and, in a recent exploration success, Shell announced a major discovery at its Rydberg (Shell 57.2%) well in the Norphlet play. Shell also discovered oil at its Kaikias (Shell 100%) well in the Mars basin, which will require further appraisal in 2015.

Last month, Shell also started oil production from its Bonga North West (Shell 55%, 40,000 boe/d) deep water development off the coast of Nigeria and recently announced a natural gas discovery at its Marjoram-1 (Shell 85%) deep-water well in Malaysia, where the Gumusut-Kakap (Shell 33%) deep-water platform is also on track for production this year.

The maintenance of blowout preventers (BOPs) has significant financial, logistical and safety implications for drilling operators and rig owners. DNV GL has now established a Joint Industry Project (JIP) to develop a risk-based maintenance methodology with the aim to deliver more effective and cost-efficient BOP maintenance. Several BOP manufacturers, operators, rig owners and shelf state regulators have already joined the JIP, and others may still come on board.

BOPs have traditionally been subject to time-based maintenance, which can create critical challenges, such as unstructured maintenance management, reduced reliability and equipment overhauls, which consequently may lead to increased operational downtime.

"A risk-based maintenance approach aims to mitigate these issues," says Rui Quadrado, project manager at DNV GL Oil & Gas. "Benefits include increased safety and operability by improving BOP performance, the introduction of lifecycle design input and increased maintainability. Ultimately, this should deliver optimal maintenance planning, thereby reducing costs."

Current regulation proposes the use of alternatives to time-based maintenance. The Petroleum Safety Authority of Norway, in particular, has focused on the drilling operators' maintenance functions, and this has increased industry understanding of risk-based maintenance.
"This JIP is looking to put this knowledge into action and provide a Recommended Practice or International Standard in which effective maintenance tasks will be identified and a cost-benefit analysis of these tasks will be evaluated," adds Quadrado. "Our experience and collaborative approach to technical challenges have already demonstrated that risk-based maintenance (through FMECA and RCM analysis) can be successfully implemented on subsea BOPs."

The work will be conducted by DNV GL and supervised by a steering committee. A kick-off meeting will take place on 25 September 2014 in Norway and industry partners are welcome to attend this.

HOUSTON, Aug. 18, 2014 /PRNewswire/ -- Apache Corporation (NYSE, Nasdaq: APA) today announced an oil discovery at the Phoenix South-1 well - the company's first discovery in Australia's offshore Canning Basin.

Wireline and formation pressure tools have confirmed at least four discrete oil columns ranging in thickness between 85 and 151 feet (26 to 46 meters) in the Triassic Lower Keraudren formation, within an overall, sand-rich section between 13,648 and 14,763 feet below sea level (4,160 to 4,500 meters).

Six light oil samples have been recovered from three intervals to date; permeability measurements from the sampled zones indicate a productive oil reservoir with preliminary estimates that there might be as much as 300 million barrels of oil in place.* Evaluation of the formation penetrated in the Phoenix South-1 is under way, and final calculation of hydrocarbon pay will depend on additional analysis.

The Phoenix South-1 well is located in permit WA-435-P, offshore western Australia, 110 miles (180 km) north of Port Hedland in 435 feet (133 meters) of water. Apache has a 40-percent interest and operatorship of WA-435-P and the adjacent permit WA-437- P; co-venturers are Carnarvon Petroleum (20 percent), Finder Exploration (20 percent) and JX Nippon (20 percent). Apache also has exercised its option to acquire 40-percent interest and operatorship of two additional adjacent permits (WA-436-P and WA- 438-P) for a total position of more than 5 million acres (20,000 square kilometers).

The area includes a number of large, undrilled structures, including the Roc prospect on WA-437-P, with potential to be significant additional oil accumulations. Further drilling and evaluation is planned for 2015.

"Although evaluation is at an early stage, Phoenix South-1 is an exciting result," said Thomas E. Voytovich, Apache's executive vice president and chief operating officer - International. "The oil and reservoir quality we have seen point to a commercial discovery. If these results are borne out by further appraisal drilling, Phoenix South may represent a new oil province for Australia. We look forward to working with our partners to continue evaluation of the area."

* Oil in place estimate based on 10th percentile probability.

Forward-looking statements

This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements can be identified by words such as "anticipates," "intends," "plans," "seeks," "believes," "estimates," "expects," and similar references to future periods. These statements include, but are not limited to, statements about future plans, expectations, and objectives for Apache's operations, including statements about drilling plans in Australia. While forward-looking statements are based on assumptions and analyses made by us that we believe to be reasonable under the circumstances, whether actual results and developments will meet our expectations and predictions depend on a number of risks and uncertainties which could cause our actual results, performance, and financial condition to differ materially from our expectations. See "Risk Factors" in our 2013 Form 10-K filed with the Securities and Exchange Commission for a discussion of risk factors that affect our business. Any forward-looking statement made by us in this news release speaks only as of the date on which it is made. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statement, whether as a result of new information, future development, or otherwise, except as may be required by law.

Marathon Oil Corporation (NYSE: MRO), through its wholly owned subsidiary Marathon Oil Exploration Limited, announced today it has signed an exploration and production sharing contract (EPSC) for Gabon offshore Block G13, which was named Tchicuate upon signing, located in the deepwater, pre-salt play. The Company was the high-bidder on the block in Gabon's licensing round in October 2013.

"We're pleased to finalize the EPSC on the newly named Tchicuate Block, which is located in the high-potential, pre-salt play offshore Gabon," said Mitch Little, Marathon Oil vice president, International and Offshore Exploration and Production. "The addition of the Tchicuate Block aligns well with our strategic focus of capturing quality and material resource in proven and emerging oil provinces, and adds depth to the Company's exploration portfolio, following our 2013 Diaman-1B discovery on the Diaba Block offshore Gabon."

The Tchicuate Block encompasses 275,000 acres with water depths ranging from approximately 3,250 to 8,250 feet. It is located approximately 50 miles offshore the coast of Gabon and near proven shallow-water, pre-salt oil discoveries. Marathon Oil holds a 100 percent participating interest and operatorship in the block. In the event of development, the Republic of Gabon will assume a 20 percent financed interest in the contract upon commencement of production. The State holds additional rights to participate in the block in the future as a co-investor.

Marathon Oil also holds a 21.25 percent working interest in the non-operated Diaba License G4-223, encompassing 2.2 million gross acres, where the Diaman-1B discovery was made in 2013.

With the oil & gas industry's push into new energy frontiers, the offshore pipeline industry is faced with greater technical challenges relating to pipelines and the expectation that it will optimize solutions to be cost effective. DNV GL is launching three new Joint Industry Projects (JIPs) to help the industry address these challenges.

The first JIP will make pipeline free span intervention less costly, the second will result in faster and more consistent pipeline repair and the last will optimize the design of pipeline components faster.

"Offshore pipelines are the veins on an offshore field development and represent a large part of the total investment and the value of the transported product can be enormous. DNV GL is committed to supporting the industry to work smarter, safer and greener. All three cooperation projects present an opportunity for the industry to work more efficiently, either through optimized and more reliable design, faster execution of projects, or safer and more robust operation", says Asle Venås, Global Director for Pipelines in DNV GL.

Free Spans in Trenches JIP
Gaps between the seabed and pipeline, known as free spans, can lead to vibrations which may damage the pipeline. "Lack of knowledge about the extent of vibrations in small gaps that typically occur on sandy seabeds means the industry is conservative and is potentially over-dimensioning designs and conducting unnecessary interventions. The DNV GL JIP aims to address this problem by developing improved free span assessments which will lead to fewer interventions and reduced cost," says Olav Fyrileiv, Project Manager, DNV GL – Oil & Gas.
The project comprises computational fluid dynamic analysis combined with a significant test program and the outcome will be an extension of DNV GL's Recommended Practice for Free Spanning Pipelines (DNV-RP-F105). DNV GL has already partnered with Dutch pipeline operator BBL Company V.O.F. and is now inviting other pipeline operators to also join the project.

Pipeline Repair JIP
Maintenance and modification technology on offshore pipelines is developing to accommodate deeper and harsher environments and reduce downtime. Technology and operational experience have been developed through several projects, such as remote pipeline operations using hyperbaric welding and Statoil's successful Hot Tap operations in the North Sea.

"DNV GL is inviting the main players in the pipeline repair equipment sector to collaborate with us in reviewing recent developments in pipeline repair and maintenance. We plan to develop formalized criteria and procedures in an updated version of DNV GL's Recommended Practice on Pipeline Subsea Repair (DNV-RP-F113). The aim is to reduce the time and cost spent on the design and execution of pipeline repairs," says Dag Øyvind Askheim, Project Manager, DNV GL – Oil & Gas.

Design of Pipeline Components JIP
Today, internationally recognized standards and recommended practices cover the limit state design of subsea pipelines. However, such design codes only provide high level guidance on how to consider pipeline components within a pipeline system.

Currently, there is not a consistent and unified approach to the design of pipeline components. With modern pipeline standards, the pipeline design is optimized and this gap becomes even more pronounced. The objective of this JIP will be to develop an approach, based on industry experience and best practice, to pipeline component design that is compatible with a modern pipeline limit state design code such as DNV-OS-F101. "The aim is to help prevent project delays, increased costs and, in some cases, compromised safety, which can happen when the interpretation of codes is stretched. We are inviting major players working with pipeline systems and components," says Jonathan Wiggen, Project Manager, DNV GL – Oil & Gas.

Aasta Hansteen and Polarled are moving the boundaries for technology, deep waters and ripple effects on the Norwegian continental shelf (NCS).

llustration: The Aasta Hansteen platform will be the largest SPAR platform in the world. (Illustration: GeoGraphic / Statoil)

"Aasta Hansteen is one of the biggest and most complex industrial projects in Europe. With the Polarled pipeline we are taking the Norwegian gas infrastructure northward across the Arctic Circle for the first time.

"We are building the largest SPAR platform in the world, and we are setting a new depth record of 1,300 meters for a field development and pipeline on the NCS," says Torolf Christensen, Statoil's head of Aasta Hansteen, at a press conference during ONS 2014.

The investments in Aasta Hansteen and the Polarled pipeline total NOK 57 billion.

The plan for development and operation was approved in 2013, and today the project is under development in several parts of the world.

The hull and the topside are being constructed in South Korea, while the equipment packages and subsea facility and pipeline equipment are delivered globally.

The first offshore work started in the summer of 2014 and involves laying of a fibre-optic cable on the seabed and installation of rocks on the seabed for the pipeline. The project is on schedule for production start-up in the third quarter of 2017.

"Aasta Hansteen is a pioneering project with regard to local ripple effects. The development has so far realized more than NOK 400 million in spinoff effects in northern Norway, and more than 200 people are involved in the construction of Aasta Hansteen and Polarled on the Helgeland coast."

"We expect considerable spinoffs in the installation work to be carried out offshore and during production drilling on the field. The main Aasta Hansteen spinoffs will occur in the field's operating phase," says Christensen.

"The Norwegian supplier industry is well positioned in the project execution. Suppliers with a Norwegian billing address are delivering more than half of the equipment packages for the Aasta Hansteen topside. In subsea equipment, 93% is being provided by suppliers with a Norwegian billing address," says Christensen.

"The combination of deep waters, harsh weather conditions and a long distance from existing infrastructure on Aasta Hansteen is unique globally. In order to meet these challenges we have cooperated closely with the supplier industry, and jointly we are developing a new deepwater standard. The expertise we acquire will be applied in new developments both on the NCS and internationally," says Helge Hagen, project manager for the Aasta Hansteen subsea development.

Norwegian prime minister Erna Solberg officially opened the Gudrun platform in the North Sea 19 August. This is the first new Statoil-operated platform on the Norwegian continental shelf (NCS) since Kristin in 2005.

Gudrun is the first in a long line of new field developments operated by Statoil, and therefore it represents a new era on the NCS.

The next in line is Valemon, which is scheduled for start-up later this year. Gina Krog and Johan Sverdrup on the Utsira High are next in the North Sea.

We also have Aasta Hansteen and Johan Castberg to come in northern Norway. Johan Sverdrup alone will ensure value creation for another 40-50 years from the NCS.

Global strategy

Gudrun is the result of a global development strategy. The jacket has been delivered by Kværner Værdal in mid-Norway, and the living quarters by Apply Leirvik at Stord in western Norway.

The topside was provided by Aibel with sub-supplies from Thailand, Poland and from Haugesund in Western Norway. The helideck was constructed in China.

Gudrun has been put on stream on time and below the cost estimate of the plan for development and operation (PDO). The global puzzle has helped keep the costs down.

The development has demonstrated the strong competitiveness of the Norwegian supplier industry.

“Gudrun has proven that we are able to take our industry into a new era with global competition and local value creation,” said Statoil’s chief executive Helge Lund in his speech at the opening.

Using the infrastructure

On Gudrun, Statoil has combined a new field development with existing pipelines and facilities. The oil and gas from Gudrun is processed on the Sleipner A platform which is located 50 kilometres further south. The gas is then piped to Europe, while the oil is piped along with the Sleipner condensate to the Kårstø processing complex north of Stavanger for shipment.

“Gudrun is a good example of how we manage to realise projects by combining new field developments with existing infrastructure. This is good value creation that helps maintain activity and extends the life of a wide range of offshore fields and facilities,” said Lund.

The recoverable reserves on Gudrun are about 184 million barrels of oil equivalent. The platform already produces 30,000 barrels per day.

BP Trinidad and Tobago LLC has announced the sanction of its Juniper offshore gas project

The project will feature the construction of a normally unmanned platform together with corresponding subsea infrastructure, a first for BP Trinidad and Tobago. Fabrication is proposed to begin in 4th quarter, 2014.

The Juniper facility will take gas from the Corallita and Lantana fields located 50 miles off the south east coast of Trinidad in water-depth of approximately 360 feet. The development will include five subsea wells and will have a production capacity of approximately 590 million standard cubic feet a day (mmscfd). Gas from Juniper will flow to the Mahogany B hub via a new ten kilometer flowline.

Juniper will become bpTT's 14th offshore production facility. Drilling is due to commence in 2015 and first gas from the facility is expected in 2017.

BPTT Regional President Norman Christie said: "Juniper demonstrates bpTT's commitment to Trinidad and Tobago over the long-term. This development is an important part of the future for bpTT because it will assist the company in meeting its natural gas commitments to the market. It is also an important step change for bpTT as it introduces subsea infrastructure to continue the development of its resources in the Columbus Basin."

BPTT operates in 904,000 acres off Trinidad's east coast. BPTT has 13 offshore platforms and two onshore processing facilities.

The Juniper project has been undertaking Front End Engineering and Design (FEED) activities since 2012.