On January 3rd, 2015, at 8.36 a.m. the Valemon gas and condensate field in the North Sea was brought on stream by Statoil and partners. Recoverable reserves from the field are estimated at 192 million barrels of oil equivalent.

"Valemon is one of several new projects on the Norwegian continental shelf that will help add value, activity and innovation, demonstrating well the long-term perspective that characterizes Statoil's activity on the Norwegian continental shelf," says Arne Sigve Nylund, executive vice president for Development and Production Norway.

Valemon is the second Statoil-operated platform to be put into production in the last nine months and also the first new platform to be operated from Bergen since Kvitebjørn came on stream 10 years ago.

The Valemon platform will be Statoil's first platform remotely controlled from shore, turning into a "normally unmanned platform" when the drilling on the field is completed in 2017.

Condensate from Valemon will be piped to Kvitebjørn for processing, and from there to Mongstad, whereas the gas will be sent to Heimdal for processing, and then transported to the market.

Heimdal, which was scheduled to be shut down in 2014, will thus get extended life as a gas hub in this part of the North Sea thanks to Valemon.

"By using the existing facilities at Kvitebjørn and Heimdal, as well as the existing pipelines, we have also reduced the costs of developing the Valemon field," says Nylund.

The Valemon topside was built in South Korea. The topsides EPC contract (engineering, procurement and construction) is a first for Statoil in Asia. The platform also has a high Norwegian content, 80 of the 120 mechanical equipment packages being delivered by Norwegian suppliers.

"The South Korean yard and a competitive Norwegian supply industry have together with a competent project organization ensured project start-up on schedule, with excellent HSE results," says Margareth Øvrum, executive vice president for Technology, Projects and Drilling.

Facts:
– Partners: Statoil Petroleum A/S (operator) 53.77 percent, Petoro AS 30 percent, Centrica Resources 13 percent, A/S Norske Shell 3.23 percent.

– When all wells have been drilled the investments in the Valemon field development project will total about NOK 22.6 billion. The platform will then have 10 production wells.

– Valemon is a high-pressure, high-temperature field.

– The steel jacket and living quarters are built at two yards in the Netherlands, the topsides in South Korea, and 80 of the 120 mechanical equipment packages on board come from Norway.

– The platform has 40 cabins, but during normal operations there will be some 17 people on board. In the longer term the platform will normally be unmanned.

Deep Down, Inc. (OTCQX: DPDW) ("Deep Down"), an oilfield services company specializing in complex deepwater and ultra-deepwater oil production distribution system support services announced it has received a large order for flying leads and ancillary equipment directly from one of the supermajor operators. The flying leads will be delivered and deployed in the Gulf of Mexico by the first quarter of 2016.

Ron Smith, Chief Executive Officer of Deep Down, Inc. stated, "We are pleased to receive this award on such a critical project and will continue to provide the best quality and service to our customers."

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

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

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

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

COSL 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.

www.statoil.com

Total has completed the flare out of the Ofon field on Oil Mining Lease (OML) 102 offshore Nigeria. The associated gas of the Ofon field is now being compressed, evacuated to shore and monetized via Nigeria LNG.

"The flare-out of the Ofon field illustrates our commitment to developing oil and gas resources around our existing hubs in Nigeria. This important milestone of the Phase 2 of the Ofon project was achieved in a context of high levels of local content," commented Guy Maurice, Senior Vice President Africa at Total Exploration & Production. "The flare-out on Ofon is also significant for Total's environmental targets, representing a 10% reduction in the Group's E&P flaring. This achievement is a clear demonstration of Total's commitment to the Global Gas Flaring Reduction Partnership promoted by the World Bank."

The Ofon field is located 65 kilometers from Nigerian shores in water depths of 40 meters. The field initially commenced production in 1997 and is currently producing about 25,000 barrels of oil equivalent per day (boe/d). This flare-out milestone will allow for the gradual increase of production towards the 90,000 boe/d production target through monetization of around 100 million cubic feet of gas per day, followed later in 2015 by the drilling of additional wells. The execution of the project also involved significant local content, including the first living quarters platform to be fabricated in Nigeria.

Total E&P Nigeria operates OML 102 with a 40% interest, alongside the Nigerian National Petroleum Corporation (60%).

Total Exploration & Production in Nigeria

In 2012, Total celebrated fifty years of its presence in Nigeria. The Group's production in Nigeria was 261,000 boe/d in 2013.

Deep offshore developments are one of Total's main growth avenues in Nigeria, where the Group operates the Akpo field in OML 130 and launched the development of the Egina field in the same lease in 2013.

Offshore production also comes from OMLs 99, 100 and 102, which are operated by the Group as part of a joint-venture with NNPC. The main fields in these leases are Amenam-Kpono, Edikan and Ofon.

Total's onshore production comes from OML 58, which it also operates as part of its joint-venture with NNPC. A project is underway to increase the lease's natural gas and condensate production capacity to supply the domestic market.

In addition, Total has significant equity production in Nigeria from its interests in non-operated ventures, particularly the SPDC-operated joint venture (10%) and the Bonga field (12.5%). Total also has a 15% interest in Nigeria LNG, which operates six LNG liquefaction trains on Bonny Island with a capacity of 21.9 million metric tons per year.

Total deploys an assertive policy to create in-country value in Nigeria - the Group is helping Nigerian contractors to build deep offshore expertise, especially in the Niger Delta, a region that is home to more than half of Total's Nigerian employees and most of its operations in the country. Local content accounted for 60% and 90% respectively for Usan and the onshore OML 58 projects, and is likely to reach 75% for the deep offshore Egina development.

Leading international oil and gas service company, ASCO, has secured a new contract for the provision of supply base services in Sandnessjøen, Norway by Statoil, commencing in July 2015.

The ten-year contract, with a value of between US$22 million and US$25 million (NOK 100 – 130 million), is for supply base services in support of Statoil's drilling and operational activities in the Northern part of the Norwegian Sea from Sandnessjøen, including the Norne, Urd and Aasta Hansteen fields.

The contract scope of supply includes the provision of warehouse management, terminal handling, oil country tubular goods (OCTG) handling, as well as management of Statoil and BP's joint subsea base in Sandnessjøen. In addition, the six-year contract has two further two-year options.

Runar Hatletvedt, Managing Director for ASCO Norge said: "This is a significant win for ASCO Norge that highlights the strength of our expertise as well as our proven track record in oilfield support services in the region. We look forward to working with Statoil in Sandnessjøen."

ASCO also manages a supply base in Mtwara, Tanzania, on behalf of Statoil, BG, Petrobras and Ophir.

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

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

N'Goma FPSO Credit: SBM Offshore

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

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

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

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

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

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

U.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).

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.

McDermott International, Inc. (NYSE:MDR) ("McDermott") announces that it has been awarded a contract to install the offshore jacket, deck and piles for the Ayatsil-A drilling platform for PEMEX Exploracion y Produccion ("PEMEX") in the Bay of Campeche Ayatsil field. The value of the award is included in McDermott's fourth quarter backlog.

Ayatsil-A jacket loaded onboard the Intermac 600 transportation and launch barge, ready for installation. (Photo: Business Wire)

"The Ayatsil-A installation award from PEMEX is a direct result of the substantial local capabilities and operations of McDermott in Mexico, and our demonstrated track record of safe and reliable platform installations for PEMEX in the Bay of Campeche," said Dominic Savarino, Vice President and General Manager, Americas. "Our unique ability to mobilize our versatile marine resources including the heavy-lift vessel, Derrick Barge 50, capable of lifting surface loads up to 4,400 tons, and the Intermac 600 transportation and launch barge was a critical component of the successful award for this fast-track installation project."

The Intermac 600 will launch the 8,400-ton jacket and the heavy-lift Derrick Barge 50 will complete the installation of the jacket, a 3,400-ton deck and other platform components in waters 400 feet deep. The total weight of the facility is approximately 15,800 tons.

The Ayatsil field is the largest discovery for PEMEX to date and is expected to boost production for the country by 150,000 barrels of oil per day. This contract award follows the successful delivery of the Ayatsil-B eight-leg jacket and deck by McDermott in July of 2014.

Increase needed to keep pace with inflation, preserve deterrent effect

As part of the Obama Administration's ongoing efforts to ensure the safe and responsible production of domestic offshore energy resources, the Bureau of Ocean Energy Management (BOEM) has administratively increased the limit of liability for oil-spill related damages from $75 million to approximately $134 million for offshore oil and gas facilities. This is consistent with recommendations to increase the liability cap from the National Commission on the BP Deepwater Horizon Oil Spill and other studies and represents the maximum increase allowable under the Oil Pollution Act of 1990.

"BOEM is taking an important step to better preserve the "polluter pays" principle of the Oil Pollution Act and further promote safe and environmentally responsible operations," said Acting Director Walter Cruickshank. "This is the first administrative adjustment since the Oil Pollution Act was enacted in 1990 and is needed to keep pace with inflation, which has increased 78 percent since then."

The administrative adjustment to the Oil Pollution Act of 1990 liability cap for offshore facilities is based on the significant increase in the Consumer Price Index (CPI) that has occurred since 1990. The liability cap is set by statute and may only be adjusted to address significant increases in the CPI. The increase to $134 million represents the maximum increase that may be implemented absent new legislation.

The increase applies to facilities handling oil and gas in federal and state waters seaward of the coastline. The liability cap applies to damages that result from oil spills, but does not apply to other liabilities such as oil spill removal costs, which remain unlimited. The rule also contains a mechanism to regularly update the limit of liability cap in the future to reflect changes in inflation over time based on the CPI.

The change to BOEM's regulations was proposed in February and the bureau fully considered all stakeholder comments before enacting this rule that will go into effect in January 2015.

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

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

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

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

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

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

• 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.

2H Offshore, an Acteon company, has teamed up with oil and gas industry leaders to develop a new design guideline for thermoplastic composite pipes (TCP) to advance the understanding and use of composite materials in the offshore industry. The Joint Industry Project (JIP) began in October and will take a year to complete. 2H teams in London, UK, and Houston, USA, are actively involved in the JIP. The work will build on existing knowledge and guidelines to achieve an industry accepted standard.

Tim Eyles, managing director, 2H, said, "Our involvement in this JIP underlines our commitment to supporting the use of composite materials within the offshore industry. Composite pipes have many advantages. Their good fatigue performance and reduced cross-sectional weight may help to overcome technical challenges in the industry, especially in deeper water and harsh environments. 2H has experience in using composite materials in risers and is committed to using emerging technologies to find the best technical solutions to meet the needs of our clients."

Statoil and its partners have decided to develop the Rutil discovery located in the Gullfaks Rimfaks valley in the North Sea. Providing close to 80 million barrels of oil equivalent, the development will extend the lifetime of the Gullfaks A platform.

The plan for development and operation (PDO) was submitted to the authorities on December 16th.

"We are pleased about the investment decision we have made that will extend the period of profitable production on the Gullfaks A platform. By using existing infrastructure and standardized solutions we are able to create great value for our owners," says Ivar Aasheim, senior vice president for field development on the Norwegian continental shelf (NCS).

"Statoil is currently implementing a major improvement effort to reduce costs and increase profitability to secure longterm activity and value creation on the NCS. The Gullfaks Rimfaks valley is a good example of this work," underlines Aasheim.

Gas and condensate will be transported in existing pipeline for processing in the gas processing facility at Kårstø north of Stavanger. The processed gas is transported to markets on the European continent.

"Production from the Gullfaks Rimfaks valley helps secure jobs and value creation from the Gullfaks field and throughout the whole value chain beyond 2030," says Kjetil Hove, senior vice president for the operations west cluster in Development and Production Norway (DPN).

The investment costs of the Gullfaks Rimfaks valley development are estimated at 4.6 billion 2014 NOK.
The Gullfaks Rimfaks valley development will consist of a standard subsea template with two simple gas production wells, and possibilities of connecting two more wells. The well stream will be connected to the existing pipeline to the Gullfaks A platform.

The Gullfaks Rimfaks valley is one of Statoil's fast track projects, aiming at realising resources quickly and cost-efficiently by for example using existing infrastructure while it is still available.

Production start is scheduled for the first quarter of 2017.

The license partners are Statoil (operator) (51%), Petoro (30%) and OMV (19%).

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

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

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

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

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

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

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

Two 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.