Oil & Gas News

Due to overcapacity in the rig portfolio the suspension periods for COSL Pioneer, Scarabeo 5 and Songa Trym have been extended.

COSL Pioneer 468 195COSL Pioneer. (Photo: Ole Jørgen Bratland/Statoil)

The suspensions are also a result of the failed attempts to mature alternative tasks for the rigs.

"When the rig contracts were signed it was challenging to ensure sufficient rig capacity. Today the activity is facing lower margins, a generally high cost level and subsequent lower profitability. It is therefore more demanding to mature profitable drilling targets," says Statoil procurement head Jon Arnt Jacobsen.

COSL Pioneer, Scarabeo 5 and Songa Trym were initially suspended until the end of the year from 8 October, 5 October and 20 November, respectively. COSL Pioneer will be suspended for an additional seven and a half months. The suspension periods for Scarabeo 5 and Songa Trym will be extended by one and a half months and one month, respectively. The extension period for Songa Trym may be reduced, or avoided, if acceleration of activities is achieved.

"I would like to emphasise that the suspensions are not related to the rig deliveries. We are very pleased with the work they have done for us. These measures are necessary due to the overcapacity of rigs compared to the assignments we are prioritising. This situation is unfortunate, and we are doing what we can to minimise the extent of the suspensions," Jacobsen says.


SnorreA 468x195The Snorre partnership has decided to adjust the schedule for the ongoing Snorre 2040 project by postponing the planned date for DG2 from March 2015 to October 2015.

There is no change in the timing of the final investment decision (DG3) and production start-up (DG4), which are planned for Q4 2016 and Q4 2021, respectively.

The early phase of the project is extended to take full advantage of the improvement potential initiated by Statoil's STEP (Statoil technical efficiency program) program and the current focus on cost efficiency within the industry.

Profitability of a new Snorre C platform is challenging and it is important for the owners to secure quality in design and cost estimates prior to entering into FEED studies.

Snorre 2040 background
– The Snorre oil field has been in production since 1992.

– The field has a complex reservoir, and represents one of the largest IOR (increased oil recovery) potentials on the Norwegian continental shelf.

– When the plan for development and operation (PDO) was submitted, the estimated recovery rate was 25%. Currently 35% of the oil is produced and the estimated recovery rate from existing infrastructure is 47% by 2040. The Snorre partners have an ambition to increase the recovery rate to 54% by installing a new Snorre C platform and importing gas to the field.

– The concept selection was made late 2013, and the new Snorre C platform is currently being matured according to plan towards a final investment decision Q4 2016 and production start-up in Q4 2021.

Statoil has decided to suspend two new rigs due to overcapacity in the rig portfolio. Transocean Spitsbergen and Songa Trym will be suspended through 2014, a period which might be extended.

StatoilRigsThe Transocean Spitsbergen (t.v.) and Songa Trym drilling rigs will be suspended through 2014.

The exploration program in the Barents Sea for 2014 is nearing completion. After Transocean Spitsbergen has completed the Saturn well the rig will cut and retrieve a wellhead in the Mercury exploration well. The job is estimated to be finished in mid-November.

Subsequently the rig will be suspended to the end of the year. The suspension is a result of overcapacity in Statoil's rig portfolio, and unsuccessful attempts to mature alternative assignments for the rig.

"The exploration program has been highly efficient. Transocean Spitsbergen drilled the last seven wells 40% faster than the industrial average in the Barents Sea. This allowed two more wells than originally planned to be drilled. We are very pleased with the work performed for us by Transocean. Unfortunately we are now in a situation of overcapacity, at the same time as the industry is facing high costs and lower profitability," says Statoil's chief procurement officer Jon Arnt Jacobsen.

Transocean Spitsbergen is planning a yard stay from 1 January 2015. The rig is under contract to Statoil to the start of 3Q 2015.

Songa Trym will be suspended after the rig has completed plugging a well on the Oseberg field in the North Sea. This job is scheduled to be completed in mid-November.

"Songa Trym has delivered well on efficiency and safety, and we would have liked to use the rig also for the rest of the year. We have tried to find new assignments for the rig, but our attempts to realize the identified options have not been successful. We are now together with our partners maturing identified drilling assignments for both rigs for 2015," says Jacobsen.

After the two rigs are suspended Statoil will have 13 rigs in activity on the Norwegian continental shelf.

HessHess Corporation (NYSE:HES) announced on Wednesday that together with its project co-owners it will proceed with the development of Stampede, an oil and gas project operated by Hess in the deepwater Gulf of Mexico.

Discovered in 2005, the Stampede Field is located approximately 115 miles south of Fourchon, La., in the Gulf of Mexico (Green Canyon Blocks 468, 511 and 512). The field is located in approximately 3,500 feet of water, with a reservoir depth of 30,000 feet. The plan initially calls for six subsea production wells and four water injection wells from two subsea drill centers tied back to a Tension Leg Platform (TLP). A two-rig drilling program is planned with the first rig commencing operations in the fourth quarter of 2015. First production is expected in 2018.

Gross topsides processing capacity for the project is approximately 80,000 barrels of oil per day and 100,000 barrels of water injection capacity per day. Total estimated recoverable resources for Stampede are estimated in the range of 300–350 million barrels of oil equivalent. The development is estimated to cost approximately $6 billion.

Hess has a 25% working interest and is operator. Union Oil Company of California, a Chevron subsidiary, Statoil and Nexen Petroleum Offshore U.S.A. Inc. each have a 25% working interest.

Hess Corporation is a leading global independent energy company engaged in the exploration

EIAlogoU.S. proved reserves of oil increase for the fifth year in a row in 2013; U.S. natural gas proved reserves increase 10% and are now at an all-time high

• North Dakota proved oil reserves surpass the Gulf of Mexico
• Pennsylvania and West Virginia account for 70% of increase in natural gas reserves

U.S. crude oil proved reserves increased for the fifth year in a row in 2013, a net addition of 3.1 billion barrels of proved oil reserves (a 9% increase) according to U.S. Crude Oil and Natural Gas Proved Reserves, 2013, released today by the U.S. Energy Information Administration (EIA).
U.S. natural gas proved reserves increased 10% in 2013, more than replacing the 7% decline in proved reserves seen in 2012, and raising the U.S. total to a record level of 354 trillion cubic feet (Tcf).


Crude oil and lease condensate

                            billion barrels

Wet natural gas

trillion cubic feet

2012 U.S. proved reserves



Net additions to U.S. proved reserves



2013 U.S. proved reserves



Percentage change



At the state level, North Dakota led in additions of oil reserves (adding almost 2 billion barrels of proved oil reserves in 2013, a 51% increase from 2012) because of development of the Bakken and Three Forks formations in the Williston Basin. North Dakota's proved oil reserves surpassed those of the federal offshore Gulf of Mexico for the first time in 2013. Texas (still the state with the largest proved reserves of oil) had the second largest increase, adding 903 million barrels of proved oil reserves in 2013.

Pennsylvania and West Virginia reported the largest net increases in natural gas proved reserves in 2013, driven by continued development of the Marcellus Shale play, the largest U.S. shale gas play based on proved reserves. Combined, these two states added 21.8 Tcf of natural gas proved reserves in 2013 (13.5 Tcf in Pennsylvania and 8.3 Tcf in West Virginia) and were 70% of the net increase in proved natural gas reserves in 2013. U.S. production of both oil and natural gas increased in 2013: Production of crude oil and lease condensate increased 15% (rising from 6.5 to 7.4 million barrels per day), while U.S. production of natural gas increased 2% (rising from 71 to 73 billion cubic feet per day).

Proved reserves are those volumes of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. An increase in natural gas prices used to characterize existing economic conditions contributed to the reported increase in proved natural gas reserves. For example, the 12-month first-of-the-month average natural spot price at Henry Hub increased from $2.75 per million Btu (MMBtu) in 2012 to $3.66 per MMBtu in 2013.

EIA's estimates of proved reserves are based on an annual survey of domestic oil and gas well operators.
U.S. Crude Oil and Natural Gas Proved Reserves, 2013 is available at: http://www.eia.gov/naturalgas/crudeoilnaturalgasreserves.

Hess Corporation (NYSE: HES) announces that production has commenced from the Tubular Bells Field, located in the Mississippi Canyon area of the deepwater Gulf of Mexico. Hess holds a 57.14 percent interest in the Tubular Bells Field and is the operator.

Chevron U.S.A. Inc. has a 42.86 percent interest.

Hess-TubularBellsImage courtesy: Hess

Following a ramp-up period, Tubular Bells is expected to deliver gross production of approximately 50,000 barrels of oil equivalent per day (25,000 barrels of oil equivalent per day net to Hess) from three producing wells by year end.

"This important achievement demonstrates our ability to successfully execute highly complex, deepwater development projects," said John Hess, chief executive officer. "We are proud to deliver Tubular Bells safely and on budget. One year after Hess took over as operator, the project was sanctioned and fast tracked with an execution schedule to first oil in just three years."

The Tubular Bells Field was discovered in 2003 and the development was sanctioned in October 2011. It lies in approximately 4,300 feet of water, 135 miles southeast of New Orleans.

Tubular Bells utilizes the first classic spar built in the United States. The design and construction were done entirely in the U.S. creating an estimated 7,000 direct and indirect jobs in Texas and Louisiana.

Hess Corporation is a leading global independent energy company engaged in the exploration and production of crude oil and natural gas.

JohanSvedrupThe gigantic Johan Sverdrup field, one of the most profitable industrial projects in Norway over coming decades, will provide enormous value.

Construction of the first phase may lead to 51,000 man-years related to Norwegian deliveries, and the field may produce revenues amounting to NOK 1350 billion. The project will provide new knowledge, new solutions and new opportunities.

"Johan Sverdrup represents all we stand for as an industry and our faith in the future. This will be a gigantic project that will secure energy supply and jobs and result in substantial spin-offs and value for Norwegian society, the industry and the partnership behind the development," says Nylund.

Johan Sverdrup is one of the biggest discoveries on the Norwegian continental shelf since the mid-1980s and ranks among the biggest developments in the years ahead.

The consultation period concerning the environmental impact assessment for the field and the power proposal will now commence.

Large Norwegian component
It is estimated that the first-phase development of the Johan Sverdrup field will create around 51,000 man-years nationally, of which as many as 22,000 are expected to be performed by suppliers in Norway and approx. 12,000 by their subcontractors.

Calculations show that 2,700 man-years will be created in an average year in the production phase, with 3,400 man-years expected to be created at peak field development.

Based on estimates from Agenda Kaupang it is possible for the Norwegian supplier industry to be awarded more than 50% of the assignments in the construction phase and around 90% in the operating phase.

"It is very important for the Johan Sverdrup development that the Norwegian supplier industry positions itself well for the opportunities lying ahead," says Nylund.

A new chapter
According to a provisional estimate, total production revenues over 50 years may amount to as much as NOK 1350 billion (1). Of this amount, corporation tax alone will give the Norwegian state NOK 670 billion in direct revenue. Total investments for the first development phase are NOK 100-120 billion (2), while production will be in the range of 315,000-380,000 barrels per day.

Looked at from the perspective of 50 years, Johan Sverdrup will be a long-term project that several generations will bring to maturity and operate. The 200 sq.km. large field will be developed in stages. The partners are currently working on various development scenarios for the various phases in order to ensure that the first construction phase forms the basis for an overall, integrated development.

"We are planning for a stepwise field development with various installations tied back to a joint field center. This will ensure continuity and comprehensive resource utilization and also generate the greatest possible added value for our owners," adds Nylund.

Depending on the future choice of capacities and technical solutions, an early estimate for full development indicates NOK 170-220 billion with daily production put at 550,000-650,000 barrels per day.

Johan Sverdrup is situated in mature acreage that has been thoroughly studied and where the most central environmental aspects are that the development receives its power from land; that produced water will be purified and re-injected into the reservoir; and that cuttings drilled with oil-based liquid will either be brought ashore, or purified and discharged offshore. This is in accordance with regulations and a permit will be applied for.

The environmental impact assessment forms part of the plan for development and operation that is expected to be handled by the Storting next year and expected to be prepared and agreed by the partners in the beginning of February 2015.

1) 2014
2) 2013

Environmental impact assessment

An important milestone for the first planning phase of the comprehensive field development has been reached: The environmental impact assessments of: the field; the power solution; and the export solutions, are ready for consultation.

This is the first part of the plan for development and operation (PDO), the plan for installation and operation (PIO) of the power transmission facilities and the plan for installation and operation (PIO) for the export solutions respectively.

They will be submitted to the Ministry of Petroleum and Energy (MPE) in the beginning of 2015 to be discussed by the Norwegian parliament (the Storting). An investment decision will also be made at that time.


Production license 501: Lundin Norway (operator - 40%), Statoil (40%), Maersk Oil (20%)

Production license 265: Statoil (operator - 40%), Petoro (30%), Det norske oljeselskap (20%), Lundin Norway (10%)

Production license 502: Statoil (operator - 44,44%), Petoro (33,33%), Det norske oljeselskap (22,22%)

Chevron Corporation (NYSE: CVX) has announced a new oil discovery at the Guadalupe prospect in the deepwater U.S. Gulf of Mexico. The Keathley Canyon Block 10 Well No. 1 encountered significant oil pay in the Lower Tertiary Wilcox Sands. The well is located approximately 180 miles off the Louisiana coast in 3,992 feet of water and was drilled to a depth of 30,173 feet.

"The discovery further demonstrates Chevron's exploration capabilities," said George Kirkland, vice chairman and executive vice president, Upstream, Chevron Corporation. "Guadalupe builds on our already strong position in the deepwater U.S. Gulf of Mexico, a core focus area where we expect significant production growth over the next two years."

ChevronThe Guadalupe well was drilled by Transocean's Discoverer India deepwater drillship.

"The Guadalupe discovery adds momentum to our growing business in North America," said Jay Johnson, senior vice president, Upstream, Chevron Corporation. "Our deepwater exploration and appraisal program continues to unlock important resources in the Gulf of Mexico."

"Chevron subsidiaries are among the top producers and leaseholders in the Gulf of Mexico, averaging net daily production of 143,000 barrels of crude oil, 347 million cubic feet of natural gas, and 15,000 barrels of natural gas liquids during 2013," said Jeff Shellebarger, president, Chevron North America Exploration and Production Company. "The company expects additional Gulf of Mexico production from the Tubular Bells and Jack/St. Malo projects by the end of the year."

Chevron subsidiary Chevron U.S.A., Inc. began drilling the Guadalupe well in June 2014. More tests are being conducted on the discovery well and additional appraisal wells will be needed to determine the extent of the resource.

Chevron U.S.A., Inc., with a 42.5 percent working interest in the prospect, is the operator of the Guadalupe discovery well. Guadalupe co-owners are BP Exploration & Production, Inc. (42.5 percent) and Venari Resources LLC (15 percent).

Repsollogo• An important natural gas discovery has been made in the Orca-1 exploratory well, 40 kilometers off the Colombian coast.
• Repsol participates with 30% in the discovery consortium, operated by Petrobras (40%) and Ecopetrol (30%).
• The well reached a depth of 4,240 meters under 674 meters of water.

Repsol carries out an intense exploration activity in order to outpace its competitors in accelerating the increase of its reserves and production.

Repsol has made a gas discovery in the deep waters of the Colombian Caribbean, 40 kilometers off the Department of la Guajira region coast. The well, named Orca-1, is especially significant as it represents the first hydrocarbon discovery in the deep waters of the Colombian Caribbean Sea.

Repsol currently participates with 30% in the Tayrona discovery consortium, operated by Petrobras with a 40% stake, and Ecopetrol, with the remaining 30%. Repsol joined the Tayrona consortium in 2010, after making an important gas discovery in the adjacent waters in the Gulf of Venezuela.

The Orca-1 well was drilled to a depth of 4,240 meters under 674 of water. The partners will now undertake the expansion phase of technical studies using the results from the well and the seismic information previously acquired in the area to determine the block's gas potential and economical possibilities.

This is the tenth positive exploratory survey carried out by Repsol in 2014. The company has carried out an intense exploration activity that has allowed it to accelerate the increase in its reserves and production and outpace its competitors.

The scale of the climate challenge requires us not only to ask how we can do more, but how we can achieve the most. Climate change doesn't stop at borders – and neither should our solutions," says Statoil CEO Eldar Sætre at the Statoil Autumn Conference.

"We need a global approach that stimulates technology innovation," Sætre continues.

In the 2014 World Energy Outlook the International Energy Agency (IEA) presents "New Policies" as the main scenario. In this scenario global energy demand rises by 37% in the period to 2040.

By 2040, the world's energy supply mix divides into four almost-equal parts: oil, gas, coal and low-carbon sources.

Statoil-Autumn conf 468cCEO Eldar Sætre (right) and Mishal Husain at the Statoil Autumn Conference 2014. (Photo: Ole Jørgen Bratland)

No matter which direction environmental policies and measures take, an enormous amount of oil and gas investment will still be needed in the years ahead to secure energy supply, according to the IEA.

A full USD 18.5 trillion will be needed in oil and gas investment from 2014-2035 in order to meet the supply needed for the IEA's "450 Scenario", which sets out an energy pathway consistent with the goal of limiting the global increase in temperature to 2°C.

"The challenge is formidable. Even in the IEA's two-degree scenario, the industry must replace four times Saudi Arabia's production of oil and 10 times Norway's production of gas just to fight natural decline," says Sætre.

EU climate targets
The European Union recently announced their target of cutting carbon emissions by 40% by 2030, which is also line with Statoil's recommendations.

"While the agreement is an important step in the right direction, now the job is to make sure that promises turn into policies, and ambitions into actions. If the EU's ambitions are backed by efficient measures, it will underpin the role of gas in the European markets, replacing coal and reducing emissions," Sætre says. Statoil is a strong advocate for a global approach towards a much higher carbon price—and has seen the results in action.
Based on Norway having one of the world's highest prices on carbon emissions, Statoil has the world's most carbon-efficient oil and gas production.

Statoil's commitment and contribution to tackling climate change goes beyond advocacy for a high carbon price and the promotion of gas.

"We are working to make our production more energy efficient. We are contributing as an industry and as a company to cuts in emissions as part of the Norwegian "Klimaforliket". And we're working to achieve more," says Sætre.

Statoil remains focused on developing carbon capture and storage, and carbon capture and use, as part of the longer-term solution.

Statoil and the entire oil industry have since the early 1990s had a commitment on the Norwegian continental shelf not to flare from routine operations.

"Globally we are now also working collaboratively against flaring through the Global Gas Flaring Reduction Partnership," says Sætre. This is a World Bank initiative aiming to eliminate global flaring by 2030.

And at the UN Climate Summit in New York in September, Statoil and partners launched the Climate and Clean Air Coalition Oil and Gas partnership.

This partnership aims to find effective solutions to detect and reduce methane emissions— which account for a significant, but underexposed share of greenhouse gas emissions.

Energy needs in Africa
One of the main focus areas of this year's Autumn Conference and World Energy Outlook report is economic development, sustainability and energy needs in Africa—focusing particularly on the sub-Saharan regions.
While almost 30% of global oil and gas discoveries have taken place in sub-Saharan Africa over the last five years, more than two-thirds of the population still lacks access to electricity.

"Statoil has over the past few years made significant gas discoveries offshore Tanzania and we are excited about the opportunities we see for a natural gas and LNG development. We already experience that expectations to Statoil's contributions are significant. Given that only around 15% of the population have access to the electrical grid, that is not difficult to understand," says Sætre.

The IEA report highlights three actions that—if accompanied by more general governance reforms— can boost the sub-Saharan economy by a further 30% in 2040: an upgraded power sector, deeper regional cooperation, and better management of energy resources and revenues through efficiency and transparency in financing.

"Our strong presence comes with a big responsibility. This is about developing a sound, sustainable and profitable business that gives the government revenues necessary for economic growth and development. It is about contributing to local capacity building, and about contributing to openness and transparency," says Sætre.

BG group-460-x-300rollsroyceRolls-Royce is proud to announce that BG Group has selected the Trent 60 DLE industrial gas turbine as the driver for the main refrigeration compressors in the proposed Lake Charles LNG Export project in Louisiana, USA.

BG Group and Rolls-Royce have also agreed the terms of a Long Term Service Agreement covering the support and maintenance of the equipment for up to 25 years that will help deliver high levels of availability for this important LNG plant. Both the equipment and service contracts are expected to be activated in the first half of 2015, subject to the US LNG plant permitting process and final investment decisions by BG Group and Energy Transfer, the developers of the project.

Each of the three LNG trains will utilise four Trent 60 DLE gas turbines as part of the Air Products C3MR refrigeration process. Each train will employ two Trent 60 DLE gas turbines driving propane compressors and two Trent 60 DLE gas turbines driving mixed refrigerant compressors for a total of twelve Trent 60 DLE gas turbines in the plant.

With an ISO rating of 54.2 MW and 43.6% thermal efficiency, the Trent 60 DLE, which is based on the aero Trent 800 with over 20 million operating hours, is the most powerful and fuel efficient aero-derivative gas turbine available. With over 300,000 hours of experience in mechanical drive, a compact plot plan and field proven extremely high levels of availability and reliability, the Trent 60 is ideal for both onshore and offshore LNG facilities.

Andrew Heath, President of Rolls-Royce Energy, said: "We're delighted with BG Group's vote of confidence in the Trent 60 DLE. We believe our aero-derivative technology will become the leader in the LNG sector, due to its superior economics. We are looking forward to a long and productive relationship with BG."

enilogoMerakes is the first exploration well drilled by Eni in the East Sepinggan Block, which was assigned to the Company in 2012 following an International Bid Round.

Eni has made an important gas finding in the Merakes exploration prospect, in the East Sepinggan Block, where Eni is operator with a 100% stake. The Block is located in the offshore East Kalimantan (Borneo), 170 kilometers south of the Bontang LNG Plant and 35 kilometers from the offshore Jangkrik field, also operated by Eni.

The finding was made through the Merakes 1 well which was drilled at a water depth of 1,372 meters and reached a total depth of 2,640 meters. The well encountered a significant accumulation of gas in the lower Pliocene clastic sequence. Merakes has crossed a hydrocarbon column of 60 meters in high quality sandstones.

Merakes is the first exploration well drilled by Eni in the East Sepinggan Block, which was assigned to the Company in 2012 following an International Bid Round. Merakes finding potential has been preliminary estimated to be 1,3 Trillion cubic feet (Tcf) of gas in place. The finding has further upside that will be assessed with a delineation campaign.

Claudio Descalzi, Eni's CEO said: "This new success further implements the Company's growth strategy in the Pacific Basin where, in addition to its presence in Indonesia, Australia and China, Eni recently signed new exploration contracts in Vietnam, Myanmar and China. Merakes finding is a significant one as it strengthens our position as operator in Indonesia. Moreover thanks to its proximity to the Jangkrik field, which is currently under development, this new gas finding could supply in the future additional gas volumes to the Bontang LNG plant. This new achievement proves once more the effectiveness of Eni's strategic approach to exploration, which is based on operating with elevated stakes in exploration phase to better valorize exploration success"

Eni has been operating in Indonesia since 2001 and currently has a large portfolio of assets in exploration, production and development which have an increasing importance in contributing to the overall Company's production growth. The company holds working interests in fourteen permits and is operator in ten of them. The exploration activities are located in acreage in the Tarakan and Kutei Basins, offshore Kalimantan, north of Sumatra, West Timor and West Papua. In the Kutei Basin in early 2014 Eni started the development activities of the deep offshore Jangkrik gas field in the Muara Bakau PSC. Eni also holds a participating interest in the development of significant gas reserves located in the Ganal and Rapak PSCs. Production activities are located in the Mahakam River Delta, East Kalimantan through the participated Company VICO Ltd (Eni 50%, BP 50%) operator of the Sanga Sanga PSC that provides an average equity production of 17,000 barrels of oil equivalent per day.

NOIATwo new studies released by the National Ocean Industries Association (NOIA) and the American Petroleum Institute (API) show significant potential added energy and economic benefits to the United States if the Eastern Gulf of Mexico and the Pacific outer continental shelf (OCS) were opened to offshore oil and natural gas development. Both studies were conducted by Quest Offshore Inc., which also conducted a study of the Atlantic OCS, which NOIA and API released last year.

"The U.S. oil and gas industry is already a major source of jobs, economic activity, revenue to state and federal governments, and affordable and reliable American energy for American consumers. We can do much more of the same with more access to the OCS," said NOIA president Randall Luthi.

All three areas – the Eastern Gulf of Mexico, the Pacific OCS and the Atlantic OCS — are currently almost entirely off-limits to offshore oil and gas development but could be included in the federal government's next five-year leasing program. If the federal government begins holding lease sales in these regions in 2018, the three studies show that by 2035:

• Pacific OCS development could create more than 330,000 jobs, spur nearly $140 billion in private sector spending, generate $81 billion in revenue to the government, contribute over $28 billion per year to the U.S. economy, and add more than 1.2 million barrels of oil equivalent per day in domestic energy production.

• Eastern Gulf of Mexico development could create nearly 230,000 jobs, spur $114.5 billion in private sector spending, generate $69.7 billion in revenue for the government, contribute over $18 billion per year to the U.S. economy, and add nearly 1 million barrels of oil equivalent per day to domestic energy production.

• Atlantic OCS development could create nearly 280,000 jobs, spur $195 billion in private sector spending, generate $51 billion in revenue for the government, contribute up to $24 billion per year to the U.S. economy, and add 1.3 million barrels of oil equivalent per day to domestic energy production.

• Development in all three study areas — the Eastern Gulf of Mexico, the Pacific OCS, and the Atlantic OCS – could, by 2035, create more than 838,000 jobs annually, spur nearly $449 billion in new private sector spending, generate more than $200 billion in new revenue for the government, contribute more than $70 billion per year to the U.S. economy, and add more than 3.5 million barrels of oil equivalent per day to domestic energy production.

"None of the benefits shown in the studies can be realized without actual sales. The key to tapping this amazing economic and energy potential is including lease sales in these areas in the 2017-2022 OCS Oil and Gas Leasing Program," Luthi said.
The studies, fact sheets and state infographics are available at www.noia.org/TapOffshoreEnergy.

BOEM Will Hold 7 Public Hearings, Accept Public Comments Nov. 7 - Dec. 22

BOEMlogoIn response to a federal court order, the Bureau of Ocean Energy Management (BOEM) has released the Draft Supplemental Environmental Impact Statement (SEIS) for Chukchi Sea Outer Continental Shelf Oil and Gas Lease Sale 193. BOEM prepared the draft SEIS using the best available science, and working in close consultation with Alaska Native tribes, federal partner agencies, state and local governments, stakeholders and the public. "After a robust and thorough process, BOEM has prepared a Draft Supplemental EIS that addresses the issues identified by the court regarding the Chukchi Sea Lease Sale 193,"said BOEM Acting Director Walter Cruickshank. "In the analysis released today, BOEM used a new exploration and development scenario to evaluate the potential environmental effects of oil and gas activities associated with Lease Sale 193. We look forward to receiving additional public input as we continue to take a balanced approach to the safe and responsible energy development in the region."

BOEM prepared the revised analysis in accordance with the April 24, 2014, remand order of the U.S. District Court for the District of Alaska. The original EIS for Lease Sale 193 was published in 2007 and the sale was conducted in 2008. Subsequent legal challenges and federal court decisions remanded the sale back to BOEM for further analysis, specifically related to the agency's estimates of production levels from likely offshore oil fields that might be developed in the Chukchi Sea. BOEM published a Notice of Intent to Prepare a Supplemental Environmental Impact Statement (SEIS) on June 20, 2014.

The analysis in the Draft SEIS issued today uses the best available data – including actual bidding data – to estimate the highest amount of production that could reasonably result from Lease Sale 193. BOEM predicts a higher exploration and production scenario than previous analyses, based on a better understanding about existing geologic structures in the region as well as improved information about where industry operators are likely to focus their development activities.

Earlier this year, Interior's Bureau of Safety and Environmental Enforcement issued a suspension of operations for all Chukchi leases issued in Lease Sale 193, which stops the lease term from running while BOEM completes this supplemental environmental review. The suspension remains in effect until BOEM completes its environmental review, as directed by the court.

The Notice of Availability for the Draft Supplemental EIS will publish in the Federal Register on Friday, Nov. 7, initiating a 45-day public comment period, which will end Monday, Dec. 22. During this time, BOEM will hold seven public hearings in Alaska, will conduct government-to-government consultation meetings with Alaska Native tribes, and will also accept public comments through regulations.gov.

The Draft Supplemental EIS is available at: www.boem.gov/ak193/PUBLIC HEARING SCHEDULE (All hearings scheduled for 7 p.m. Alaska Time.)

Repsol• A high quality oil net pay of over 150 meters thick has been discovered.

• The well, named León, is located 352 kilometers offshore the Louisiana coast in ultra-deep waters in the United States' Gulf of Mexico.

• With a total depth of 9,684 meters, it is one of the deepest wells operated by Repsol, which has a 60% stake in this license.

• The Gulf of Mexico is amongst the world's most profitable and promising deep water plays. Repsol holds 119 blocks in the area.

• The United States already represents around 10% of the group's total production.

• In 2009 Repsol made one the most important discoveries in this region, Buckskin, 50 km from León, which is in the final stages of evaluation prior to its development.

• With the León discovery Repsol continues to strengthen its position in the United States, which is one of the company's key strategic areas.

Repsol has made a new discovery of high quality oil in the United States' Gulf of Mexico. The find was made 352 kilometers from the Louisiana coast in an ultra-deep water well named León, located in the Keathley Canyon 642 block.

Repsol is the operator of the discovering consortium. The well found more than 150 meters of net oil pay within a column of over 400 meters. The well was drilled in water 1,865 meters deep, and reached a total depth of 9,684 meters, making it one of the deepest wells operated by the company.

The company has a long experience in deep-water well drilling and is internationally recognized for its technological capacity with cutting-edge projects in hydrocarbon exploration and production such as the Kaleidoscope and Sherlock projects.

Repsol has a 60% participation in the license, with Colombia's Ecopetrol holding the remaining 40%.

The US Gulf of Mexico is amongst the world's most profitable and promising deep water plays. Repsol holds 119 blocks in this prolific area together with a share in the Shenzi field, which boasts 16 wells in production connected to two platforms.

In 2009, Repsol had already made one of its most important discoveries in this region. The Buckskin well, 50 kilometers from León, was, like the León discovery, one of the deepest wells operated by the company. The resource potential being carried out by the current operator will lead to a development plan for this and other fields in the near future.

Repsol in the United States

With the León discovery Repsol continues to strengthen its position in the United States, which is one of the company's key strategic regions.

Repsol has mining rights in the country over blocks located in the Gulf of Mexico (Green Canyon, Alaminos Canyon, Atwater Valley, Garden Banks, Keathley Canyon, Mississippi Canyon and Walker Ridge) and Alaska. Additionally, the company is developing unconventional resources in the Mississippian Lime play.

With the addition of new production during 2014, the United States already represents almost 10% of the company's total hydrocarbons output. Repsol has its second largest corporate headquarters in Houston and employs more than 600 people in the United States.

VaalcoLOGOVAALCO Energy, Inc. (NYSE: EGY) has announced that the Company has entered into the Subsequent Exploration Phase ("SEP") on Block 5 offshore Angola together with its working interest partner, Sonangol P&P, as provided for in the Production Sharing Agreement signed in 2006 with the Republic of Angola.

The SEP extends the exploration license for an additional three year period such that the new expiry date for exploration activities is November 30, 2017. The SEP requires the Company and its partner to acquire a 3D seismic program covering six hundred square kilometers and to drill two additional exploration wells. The seismic obligation has been satisfied with a seismic program already completed covering 1,058 square kilometers over the outboard portion of the block.

By entering the SEP, the Company is now required to drill a total of four exploration wells during the exploration extension period. The four well obligation includes the two well commitment under the primary exploration period that carries over to the SEP period. A ten million dollar assessment (five million dollars net to VAALCO) applies to each of the four commitment exploration wells, if any, that remain undrilled at the end of the exploration period in 2017.

As previously announced, the Company has contracted for the Transocean "Celtic Sea" semi-submersible rig to drill the first exploration well, the post-salt, Kindele-1 well. The Kindele well is targeting the Mucanzo sand (Pinda group) with a planned total depth of 2,250 meters in a water depth of 101 meters. Gross unrisked recoverable resources are estimated to be between 20-49 million barrels. The rig is currently estimated to be on location in mid-December 2014.
The decision to enter the SEP was made in part to remove uncertainty that the primary term of the exploration license would be extended by the Republic of Angola before the November 30, 2014 expiration date.

Steve Guidry, Chairman and CEO, commented, "We believe entering into the SEP is a sound strategy for the Company. Although the SEP comes with additional commitments, we believe this is a coveted block with potential in the deep syn-rift and sag play. The SEP allows VAALCO and its partner to properly assess the results of the current seismic reprocessing that is being merged with previously licensed seismic data through pre-stack depth migration. This will help us determine the best opportunities in the pre-salt horizons. The action we took to enter into the SEP removes the uncertainty of an exploration license extension and allows us to focus on our exploration activities on the block."

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