Saturday, May 18, 2013

Gazprom Could Bail Out Cyprus in Gas Deal

Russian state gas giant Gazprom may be in talks with the Republic of Cyprus government about a bailout of the cash-strapped country in return for exploration concessions in its offshore territories, according to reports.

Cyprus' parliament rejected a European Union bailout package Tuesday that included a measure that would have seen everyone with a savings account in the country take a one-off levy of up to 9.9 percent on savings of more than $25,800 (EUR 20,000). Many savers in the country include Russian expats.

Instead, Cyprus could make a deal with Gazprom, which has offered the Republic of Cyprus a plan in which Gazprom would undertake the restructuring of the tiny country's banks in exchange for exploration rights for natural gas in the country's Exclusive Economic Zone, according to the Greek Reporter website.

However, although Russian and Cypriot finance ministers have been holding talks over the Mediterranean island's financial crisis, Gazprom has not confirmed whether or not it is involved.

Cyprus has already granted concessions to several companies in its EEZ, including Italy's ENI, Korea Gas Corporation, Total and Noble Energy. In December 2011, Noble discovered the Aphrodite gas field, which it estimates holds up to 9 trillion cubic feet of gas.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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GeoPark Starts Up Production at Colombia Wells

GeoPark Holdings Limited announced the successful drilling, testing and putting into production of two new oil wells in Colombia: Max 2 in the Max oil field in the Llanos 34 Block and La Cuerva CH NE 1 in the La Cuerva oil field in the La Cuerva Block. GeoPark operates both blocks - with a 45-percent working interest in Llanos 34 Block and a 100-percent working interest in La Cuerva Block.

GeoPark drilled and completed the Max 2 well to a total depth of 10,866 feet (3,312 meters). A test conducted with an electrical submersible pump (ESP) in the Guadalupe formation, at approximately 10,171 feet (3,100 meters), resulted in a production rate of approximately 1,532 barrels of oil per day (bopd) of 13.7 API oil, with less than a 1 percent water cut, through a choke of 19 millimeters (mm) and well head pressure of 70 pounds per square inch (psi). Further production history will be required to determine stabilized flow rates and the extent of the reservoir. Surface facilities are already in place and the produced crude oil is now being marketed and sold. The Max oil field was discovered in March 2012 with the Max 1 well, which is currently producing at a rate of approximately 1,031 bopd.

GeoPark drilled and completed La Cuerva CH NE 1 well to a total depth of 4,196 feet (1,279 meters). A test conducted with an ESP in the Carbonara C5 formation, at approximately 3,855 feet (1,175 meters), resulted in a production rate of approximately 440 bopd of 20.8 API oil, with a 14% water cut, through a choke of 8.7 mm and well head pressure of 100 psi. Further production history will be required to determine stabilized flow rates and the extent of the reservoir. Surface facilities are already in place and the produced crude oil is now being marketed and sold.

GeoPark has interests in ten exploration, development and production blocks in Colombia - in addition to interests in six blocks in Chile and three blocks in Argentina. During 2013, GeoPark will carry out a 35-45 well drilling program in Colombia and Chile - with a total expected work program investment of $200-230 million.

James F. Park, CEO of GeoPark, said: "Since acquiring our Colombian projects just one year ago, we have hit the ground running and been able to record continuous growth in our crude oil production -- both from exploration and development drilling. We are also pleased that our Colombian drilling activities are matching our recent drilling successes in Chile and leading to overall increases in production and cash flow. We look forward to further positive results from our $200+ million investment program through 2013."

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MGM Energy Completes Ops at Canol Well

MGM Energy Corp. announced early results from its East MacKay I-78 well drilled this winter to test the Canol shale formation on MGM Energy's EL 466B in the Central Mackenzie Valley.

The East MacKay I-78 well, a vertical well, spud January 27, 2013 and reached target depth of 6,565 feet (2,001 meters) Feb. 15. Following logging, casing and the running of the completion string, the drilling rig was released Feb. 25. Drilling operations proceeded without incident and all formations were present as expected. In particular, the primary target, the Canol shale, was found between 5,968 feet and 6,296 feet (1,819 meters and 1,919 meters), and the Bluefish formation, the secondary target, was found between 6,352 and 6,421 feet (1,936 meters and 1,957 meters). Cores were taken within the Canol and Bluefish formations, as well as the upper Hume formation, immediately below the Bluefish. A full suite of electric logs was run once drilling was completed.

Testing operations on the Bluefish formation began on March 2, 2013. One zone of the Bluefish formation was fractured, using a small 20 tonne frac energized with nitrogen. The frac was successful, with emplacement of the sand. After flowing back approximately 30 percent of the frac fluid, the well ceased flowing due to lack of formation pressure. Rather than undertaking operations to resume the flow, and given the seasonal constraints of operating in the Central Mackenzie Valley, the decision was made to discontinue testing of this secondary zone to ensure sufficient time to test the primary Canol target.

Testing operations on the Canol formation began March 4. The Canol formation was fracked in three stages, with one stage having two perforation zones. Each of these fracs was again small, ranging from 23 tonnes to 35 tonnes, using a total of 2,450 barrels of frac fluid. All fracs were successful and all were energized with nitrogen. Approximately 70 percent of the frac fluid was recovered in the first five days after fracking. During that time, the well continued to clean up. Over the four day period of March 10-14, the well returned approximately 140 barrels of fluid consisting of a mixture of frac fluid, and formation hydrocarbons, the latter consisting of light, sweet, crude oil and natural gas. Throughout this period, nitrogen was used to assist in lifting fluids from the well. Because of seasonal constraints on activity, well testing operations in the Canol formation were concluded March 15 and equipment has since been demobilized. In order to obtain pressure data, gauges have been left in the hole, and are expected to be retrieved in the summer/fall of 2013.

MGM Energy also drilled, sampled and monitored three water wells in the area immediately adjacent to the I-78 well. Samples of water were taken before, during and after the fracs. The results of this monitoring are ongoing and, along with water samples, are being shared with regulators and governments.

Well operations were conducted in a remote area and in harsh weather conditions. Notwithstanding this, MGM Energy reports that no material environmental or safety incidents occurred at any stage of the project.

"We are very excited with the early results of the well," said Henry Sykes, President of MGM Energy Corp. "The results are quite consistent with our expectations. While it isn't possible to establish ultimate flow rates with a vertical well and the small fracs undertaken, at this point we've identified the presence of hydrocarbons in the Canol shale underlying our lands. One or more horizontal wells will need to be drilled to establish the best method of completing these wells and the flow parameters and, ultimately, to determine a type curve for these wells. In the near term, a great deal of work and analysis remains to be done with respect to information obtained and cores taken during the project, and that work will take some months to complete. We look forward to providing periodic updates as material information becomes available. We also look forward to working with regulators and local communities to ensure that the benefits of responsible development of the Canol shale are well understood and quantified. And finally, we wish to gratefully acknowledge the support we received from the local communities throughout our operations."

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MGM Energy Completes Ops at Canol Well

MGM Energy Corp. announced early results from its East MacKay I-78 well drilled this winter to test the Canol shale formation on MGM Energy's EL 466B in the Central Mackenzie Valley.

The East MacKay I-78 well, a vertical well, spud January 27, 2013 and reached target depth of 6,565 feet (2,001 meters) Feb. 15. Following logging, casing and the running of the completion string, the drilling rig was released Feb. 25. Drilling operations proceeded without incident and all formations were present as expected. In particular, the primary target, the Canol shale, was found between 5,968 feet and 6,296 feet (1,819 meters and 1,919 meters), and the Bluefish formation, the secondary target, was found between 6,352 and 6,421 feet (1,936 meters and 1,957 meters). Cores were taken within the Canol and Bluefish formations, as well as the upper Hume formation, immediately below the Bluefish. A full suite of electric logs was run once drilling was completed.

Testing operations on the Bluefish formation began on March 2, 2013. One zone of the Bluefish formation was fractured, using a small 20 tonne frac energized with nitrogen. The frac was successful, with emplacement of the sand. After flowing back approximately 30 percent of the frac fluid, the well ceased flowing due to lack of formation pressure. Rather than undertaking operations to resume the flow, and given the seasonal constraints of operating in the Central Mackenzie Valley, the decision was made to discontinue testing of this secondary zone to ensure sufficient time to test the primary Canol target.

Testing operations on the Canol formation began March 4. The Canol formation was fracked in three stages, with one stage having two perforation zones. Each of these fracs was again small, ranging from 23 tonnes to 35 tonnes, using a total of 2,450 barrels of frac fluid. All fracs were successful and all were energized with nitrogen. Approximately 70 percent of the frac fluid was recovered in the first five days after fracking. During that time, the well continued to clean up. Over the four day period of March 10-14, the well returned approximately 140 barrels of fluid consisting of a mixture of frac fluid, and formation hydrocarbons, the latter consisting of light, sweet, crude oil and natural gas. Throughout this period, nitrogen was used to assist in lifting fluids from the well. Because of seasonal constraints on activity, well testing operations in the Canol formation were concluded March 15 and equipment has since been demobilized. In order to obtain pressure data, gauges have been left in the hole, and are expected to be retrieved in the summer/fall of 2013.

MGM Energy also drilled, sampled and monitored three water wells in the area immediately adjacent to the I-78 well. Samples of water were taken before, during and after the fracs. The results of this monitoring are ongoing and, along with water samples, are being shared with regulators and governments.

Well operations were conducted in a remote area and in harsh weather conditions. Notwithstanding this, MGM Energy reports that no material environmental or safety incidents occurred at any stage of the project.

"We are very excited with the early results of the well," said Henry Sykes, President of MGM Energy Corp. "The results are quite consistent with our expectations. While it isn't possible to establish ultimate flow rates with a vertical well and the small fracs undertaken, at this point we've identified the presence of hydrocarbons in the Canol shale underlying our lands. One or more horizontal wells will need to be drilled to establish the best method of completing these wells and the flow parameters and, ultimately, to determine a type curve for these wells. In the near term, a great deal of work and analysis remains to be done with respect to information obtained and cores taken during the project, and that work will take some months to complete. We look forward to providing periodic updates as material information becomes available. We also look forward to working with regulators and local communities to ensure that the benefits of responsible development of the Canol shale are well understood and quantified. And finally, we wish to gratefully acknowledge the support we received from the local communities throughout our operations."

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CNPC to Start Oil Production in Afghanistan Soon

CNPC to Start Oil Production in Afghanistan Soon

HONG KONG - China's largest oil company is due to start commercial production of crude oil in Afghanistan shortly, heralding a resource boom that could transform the country's economy over the next decade, the country's mining minister said.

Extraction of metals and oil could account for 45% of Afghanistan's gross domestic product by 2024, Minister of Mines Wahidullah Shahrani told The Wall Street Journal Wednesday on the margins of an investment and mining conference where he is meeting potential investors.

Recent surveys have shown Afghanistan to be endowed with rich unexploited assets, but its security situation could be a sticking point for some investors.

Mr. Shahrani's comments follow President Hamid Karzai's accusations this month of U.S. collusion with the Taliban in the war-hit country, at a time when the government is trying to negotiate how many, if any, U.S. and NATO forces will remain after their mandate ends next year.

Nearly all of Afghanistan's recoverable mineral resources, estimated by the U.S. Geological Survey to be worth $1 trillion, are still under the ground, said the minister, who has held the mining portfolio for the past three years.

Output from China National Petroleum Corp. wells in northern Afghanistan will rise from zero now to 25,000 barrels a day by the end of the year, and to 40,000 barrels a day in 2014, with all the crude to be initially exported by truck through one of Afghanistan's northern neighbors, Mr. Shahrani said. The project will require an investment of $600 million, he said.

"The wells are ready for production," he said. "If we complete negotiations with our northern neighbor in the next two to three weeks, then production of the crude will begin with an initial 5,000 barrels" a day, he said.

He declined to identify which of the three northern border countries--Turkmenistan, Uzbekistan or Tajikistan--is involved, describing the talks as "very advanced". And he didn't say whether CNPC intended to move the crude to China.

Further out, Afghanistan's oil output will keep rising, providing enough of the fuel to feed a 44,000-barrel-a-day oil refinery, the country's first, which is due to be completed in two to three years.

Production from the Amu-Darya Basin, where state-owned CNPC and its Afghan partner are working, could be followed by output from the nearby Afghan-Tajik basin, from a consortium comprising Dragon Oil PLC, privately held Kuwait Energy and Turkiye Petrolleri AO, which by May should have finalized terms of an exploration and production agreement, Mr. Shahrani said.

The consortium was awarded two of the 12 blocks at Amu-Darya in December, he said.

"The geological structures there are very promising based on seismic surveys," he said, adding that exploration and test drilling would take several years.

For now, Afghanistan has to import all its fuel, mainly from Central Asia, with this being the country's largest single import item.

From May onward, Afghanistan will put additional oil, iron ore, gold and copper blocks up for international tender, the minister said.

A major obstacle to exports from landlocked Afghanistan is a lack of rail links--the only one at present is a 91-kilometer length to Uzbekistan, which connects to a central Asian network.

In a second phase, a 227-kilometer "trans-Caspian" Asian Development Bank-funded rail link to Turkmenistan, joining it to Turkey and Europe, will be built, the minister said.

Another Afghan coal and copper project is being developed by a Chinese consortium, led by state-run MCC China Metallurgical Group. The project, in Aynak, Logar province, involves building a rail link from Pakistan to Uzbekistan, which will require $4.4 billion to execute. First copper output is slated for 2014, Mr. Shahrani said.

The U.S. Department of Defense has raised major questions about whether the cost of an extensive rail system could be justified on commercial grounds, The Wall Street Journal reported in October.

Meanwhile, the government is in the final stages of talks with an Indian consortium led by the Steel Authority of India Ltd. to develop what the minister said is Asia's largest iron-ore deposit, at Hajigak, in central Afghanistan.

This will require an investment of $12 billion-$14 billion over the next decade and includes power plants as well as an export rail link that the consortium will build, he said.

Contracts are expected to be finalized by May for four major gold and copper projects, he said.

In recent years, extensive regulatory and procedural reforms introduced by the government, including a new mining law adopted in February, have given investors "more confidence about the way they will be treated and the way their investments are going to be properly protected," Mr. Shahrani said.

Foreign investors can take 100% control of projects but are encouraged to bring in local companies, the minister said, noting Afghanistan doesn't have state mining companies because "global experience has shown that in most countries they are not that effective."

"We are heading towards a transition at the end of 2014...heavy investments have been made to enhance the capability of our security forces with the active involvement of NATO and the U.S. government," he added.

Copyright (c) 2012 Dow Jones & Company, Inc.

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Expiring April Nymex Crude Oil Settles Up

Crude-oil futures prices settled higher Wednesday, fueled by higher refinery processing rates and despite concerns over signs of weak gasoline demand ahead of the peak driving season.

Traders cautioned that a series of factors make the rally, which follows a steep selloff a day earlier, less meaningful that it seems on its face.

The late surge in the front-month April contract on the New York Mercantile Exchange came ahead of its expiration and likely was steered by investors making last minute adjustments. The contract went off the board at the lowest expiration day price for crude since December.

The Energy Information Administration reported U.S. crude oil stocks fell by 1.3 million barrels last week, while analysts expected a 1.7 million barrel rise. The surprise decline followed nine straight weeks of increases that plumped up inventories by 24 million barrels. Even with the decline, the surplus of crude to its five-year norms widened to a two-month high of 12%. Analysts also noted most of the drop in crude stocks occurred on the isolated West Coast, which isn't reflective of the national trend.

EIA said crude oil runs rose 520,000 barrels a day, to 14.5 million barrels a day, which is supportive for the market. But the large gain came from the week-earlier level that was the lowest in two years.

"The data was actually bearish," said Gene McGillian, broker and analyst at Tradition Energy. "We saw a draw in crude, but we also saw weak demand for gasoline" heading into the start of the spring-summer driving season.

Mr. McGillian said the main impetus for gains in oil futures was the fact fears receded over the fiscal crisis in Cyprus and how steps to address it could ripple through struggling European economies. "We've still got 380 million barrel of crude and that's a lot of oil in storage," he said. "We're not being driven higher by tight supplies at all."

Nymex April-delivery light, sweet crude oil expired 80 cents higher, at $92.96 a barrel after a late session high of $93.30 a barrel. May crude oil settled 98 cents higher, at $93.50 a barrel.

ICE North Sea Brent crude oil for May settled $1.27 higher, at $108.72 a barrel, after settling Tuesday at the lowest level since Dec. 10.

Stocks at Cushing, Okla., the delivery point for the Nymex crude oil contract, dropped by 286,000 barrels in the week to their lowest level in three months, but analysts noted inventories remain close to record highs.

"It's a little too early to say we're seeing the start of the drawdowns at Cushing," said Andy Lebow, senior vice president for energy futures at Jefferies Bache. Cushing inventories are 5.5% below the record high hit in early January, but 27%, or 10.5 million barrels, above the year-earlier level. That's the smallest year-on-year surplus since Aug. 3, 2012.

The EIA data showed implied U.S. oil demand averaged 17.765 million barrels a day, down 4.5%, or 832,000 barrels a day, from a week earlier, and the lowest since Jan. 4. Demand for gasoline, the most widely used petroleum product in the nation, fell 303,000 barrels a day in the week, to a two-month low of 8.324 million barrels a day. EIA said gasoline stocks fell 1.476 million barrels, against expectations of a 2-million barrel drop last week. Traders noted a sharp drop in imports, but James Beck, the EIA official in charge of the weekly report, said the drop was likely due to typical week-to-week swings in ship arrivals rather than a trend toward lower imports.

Goldman Sachs analysts said in a note pressures on European refinery margins will likely mean they will be pushing out more gasoline for export to the U.S. in the near term.

Reformulated gasoline blendstock futures for April rebounded sharply late in the session, but traders said the move likely reflected bargain buying after Tuesday's steep selloff.

April-delivery RBOB gasoline settled 7.12 cents higher, at $3.1163 a gallon.

April heating oil settled 2.80 cents higher, at $2.8943 a gallon. EIA said distillate stocks (heating oil/diesel) fell 672,000 barrels, near the expected 900,000-barrel drop.

Copyright (c) 2012 Dow Jones & Company, Inc.

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Gazprom Wants Stake in Eni's Mozambique Gas Assets

Italian energy company Eni SpA is willing to talk to OAO Gazprom about a natural gas deal in Mozambique, although there has been no interest expressed by the Russia behemoth, Chief Executive Paolo Scaroni said Wednesday.

When ask to comment on speculation about interest from the Russian company, Mr. Scaroni said: "This is news to us especially considering how much gas Gazprom has of its own."

Mr. Scaroni told reporters on the sidelines of a conference in Ravenna, northern Italy: "In the search for a partner in the Mamba [field] in Mozambique, we will listen to them [Gazprom], talk to them," referring to the excellent relationship between the two companies. Eni is Gazprom's biggest international corporate buyer of its gas.

Gazprom is interested in a stake in Eni's project in Mozambique but hasn't made an offer yet, said Sergei Kuprianov, a spokesman for the Russian company. He added that discussions are ongoing.

Last week, Eni agreed to sell a 20% stake in its 70% holding to China National Petroleum Corp. for $4.21 billion in a giant offshore gas asset in Mozambique.

Eni has said it has found reserves of 75 trillion cubic feet in the Mozambique field. According to Bernstein Research this amount corresponds to four years of total European gas demand. It is Eni's largest gas find.

Copyright (c) 2012 Dow Jones & Company, Inc.

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UK Budget: Decom Tax Relief Welcomed by Oil, Gas Sector

Osborne To Introduce 'Generous' New UK Shale Gas Tax Regime

Measures announced by the UK Chancellor in his 2013 Budget to guarantee tax relief on the decommissioning of oilfields on the UK Continental Shelf have been welcomed by the UK oil industry.

Oil & Gas UK Chief Executive Malcolm Webb commented in a statement:

"The industry has been working closely with the Treasury since the 2011 Budget to resolve the long-standing problem of uncertainty on decommissioning tax relief. The measures announced today will for the first time ever give companies the certainty they need over the tax treatment of decommissioning.

"At no cost to the Government, it will speed up asset sales and free up capital for companies to use for investment, extending the productive life of the UK continental shelf."

Decom North Sea (DNS), a forum specializing in UK decommissioning, said the new measures will boost the sector by giving increased certainty, in turn leading to new jobs and investment in new technology. DNS pointed out that decommissioning expenditure in the North Sea is forecast to top $1.5 billion (GBP 1 billion) within a few years.

"The Chancellor's confirmation of tax relief through Decommissioning Relief Deeds will help ease one of the greatest concerns facing the North Sea industry and lead to investment and ultimately more jobs," DNS Chief Executive Brian Nixon said.

"Once assets have been recognized as nearing the end of their economic lives, we believe the Budget will lead to operators being able to move forward with their decommissioning plans, which will in turn help to reassure the hundreds of supply chain companies and encourage them to consider investment in new equipment or tooling or to attract new staff."

Meanwhile, Derek Leith – head of oil and gas taxation at Ernst & Young in Aberdeen, Scotland – pointed out that the announcement would act as a gateway to greater investment in the North Sea, creating an active market that is attractive to companies across the oil and gas industry, from super majors to niche operators.

"Cementing the promise of contracts that guarantee tax relief on costs associated with deactivating and dismantling oilfields during the lifetime of this, and future parliaments, removes another layer of fiscal uncertainty from the UK Continental Shelf and should facilitate the transfer of assets," Leith said.

"Smaller companies that had previously been priced out of potential deals will now be in a position to maximise recovery from existing infrastructure, while larger players will be able to free up capital to fund further exploration and production."

In his Budget, the Chancellor also announced that he would introduce a "generous" new tax regime designed to stimulate early investment in the UK's burgeoning shale gas sector.

The new shale gas tax regime will include a field allowance. Meanwhile, new planning guidance on shale gas projects, along with specific proposals to help local communities to benefit from shale drilling, would follow later in 2013, he said.

"Shale gas is part of the future and we will make it happen," Osborne said in his Budget statement to Parliament.

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.

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Groups Praise Revenue Sharing Bill, Call for More Access to US Acreage

The American Petroleum Institute (API) and National Ocean Industries Association welcomed an offshore revenue sharing bill proposed by Sen. Lisa Murkowski (R-Alaska) and Sen. Mary Landrieu (D-La.) Wednesday.

The senators this week introduced Fixing America's Inequality with Revenues (FAIR) Act, which is designed to ensure all energy-producing states receive a full share of the revenues they help produce while also encouraging investments in clean energy and conservation.

"The federal treasury benefits from the royalties and taxes on production in federally owned waters off Alaska's coast," said Murkowski in a statement Tuesday. "Providing a portion of that money to Alaska would help the state strengthen its emergency response capabilities and build critical infrastructure, such as airfields, deepwater ports, and docks that will help safely open the Arctic, which will further increase federal revenues."

The FAIR Act would provide up to 37.5 percent of all revenues from offshore development to coastal states, including revenues from oil and gas and the development of alternative and renewable energy resources.

Under the bill, states would automatically receive 27.5 percent of these revenues, 25 percent of which would go to the coastal communities most impacted by offshore development. States are eligible for an additional 10 percent if they establish funds to support projects relating to clean energy or conservation.

The bill also would expand revenue sharing onshore to include renewable energy production on federal lands at the same 50-percent share currently given for oil and gas production. The bulk of revenues from offshore development, 62.5 percent, would still flow to the federal government.

The legislation marks an important step towards an all-of-the-above energy policy for the United States, said API Director of Upstream & Industry Operations Erik Milito in a statement Wednesday.

"As today's successful lease sale in the Central Gulf of Mexico demonstrates, the industry is investing billions in American energy development but could do more if additional areas are opened for business," Milito commented. "Expanding access could create one million new jobs, generate $127 billion in government revenue in under a decade, and dramatically increase domestic energy production."

Allowing all U.S. coastal states to share in prospective future revenue from both traditional and renewable offshore energy activities is sound public policy, NOIA President Randall Luthi commented in a Wednesday statement. The group has long supported revenue sharing as fair and equitable treatment for coastal states supporting responsible offshore oil and gas exploration and development.

"However, steps must be taken to ensure that lease sales are actually conducted in new areas where they're currently prohibited or else the revenue is merely theoretical."

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

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