Executives of publicly traded shipping and offshore drilling companies have a legal duty to act in the interest of the shareholders of their respective organizations.

To fulfill this duty, executives and their financial managers must identify and undertake honest and ethical investment opportunities that offer a greater investment return than shareholders would otherwise be able to make in the open financial markets for the same level of risk.

To put it bluntly, if company management doesn’t produce enough growth for investors, the investors may decide to entrust their money elsewhere and the company’s stock price will fall.

When it comes to creating growth within shipping and offshore drilling companies, financial managers typically have two options. They can either build a new vessel or acquire an existing vessel from another company.

This article looks at the financial analysis used by drilling companies when determining whether or not it makes sense “financially” to build a brand new drilling rig.

For our case study, we’ll need to consider estimated construction costs, operating expenses and revenues of a state-of-the-art $800 million 6th generation drillship.  We’ll also assume the ship will have a service life of 20 years.

The Opportunity Cost of Capital:

The first step in our decision of whether or not to build a new ship is to consider the “opportunity cost of capital“.

We’re all familiar with the expression “a dollar today is worth more than a dollar tomorrow”. If you had the choice of $10,000 today or $10,000 a year from now, which option would you rather have?

If you’re like most people you’d probably opt for $10,000 today. If for no other reason, you could put the money in a bank account and earn interest on it for the year.

The opportunity cost of capital is a business term that places a value on exactly how much more a dollar is worth today vs. a dollar a year from now (expressed as a percentage). In the example above, we chose to collect the $10,000 today vs. waiting a year to collect it.

Had we instead waited a year to collect the same $10,000 we would have lost out on the interest of investing that money in bank savings account. If the bank was paying 2% interest, that 2% represents our opportunity cost of capital.

In other words, it cost us 2% of our capital (the $10,000 that was owed to us)  deciding to wait a whole year to get paid.

The concept of the “opportunity cost of capital” helps financial managers analyze investment options and cashflows on an “apples to apples” basis vs. comparing money received in one time period to money received in another time period.  As you’ll see in a bit, we’ll use this principle when determining the economic viability of our hypothetical drillship project.

In this particular case, we’ll assume that the opportunity cost of capital for building a new drillship is 10%. In other words, the shipping company is expecting to earn at least a 10% return on their investment in a new drillship or else they may as well invest the money in stocks and bonds of similar risk to save the hassle of managing a shipyard project.

Understanding “Net Present Value”

With our opportunity cost of capital determined, we can then “discount” all projected future cashflows (revenue minus expenses) to find the value in today’s dollars of what our drillship investment will “earn” us in the future. The value of the project in “today’s” dollars is also called the “Net Present Value” or “NPV” of the investment.

For example, lets say the opportunity cost of capital for the $10,000 we talked about above was 10% and we wouldn’t receive the $10,000 until the end of 5 years. How much is $10,000 at 10% interest 5 years down the road worth today? To calculated this we simply divide the “principle”, which in this case is the $10,000, by (1.10)^5.

In this simple example, $10,000 at 10% opportunity cost of capital paid 5 years from now is “only” worth $6,209.

Getting back to our drillship example, to calculate the “Net Present Value” of our project, we need to estimate the annual (sometimes called “incremental”) cashflows for each of the 20 years the ship is in operation and then “convert” these cashflows to today’s dollars using the NPV formula we used in the example above.

Remember, we had to cough up $800 million to build our drillship, so the goal here is for the “net present value” of all future cashflow from operating the ship to be greater than $800 million. If the “net present” value of our ship building project is negative (including the cost of the ship) then we are better off foregoing the project and investing the $800 million in something else.

Hopefully I haven’t confused you too badly up to this point, but don’t worry if I have!  To bring the whole picture together, I’ve created some simple spreadsheets in Excel (below) to help illustrate the entire process.

Projected Expenses:

Now that the drilling company has agreed on an appropriate “opportunity cost of capital”, the company must consider the projected expenses of operating the drillship over its 20 year service life. To keep things relatively simple, I have broken these costs down into 3 categories:

Construction Costs: Let’s assume that the drilling company is paying cash for the construction of the new drillship with $400 million being paid at the start of the project and the remaining $400 million paid at the beginning of the next year (we’ll assume a two-year construction period).

Operating Costs: As you can probably imagine, the yearly operating costs for a 6th generation drillship can add up quickly. Between crew salaries, general maintenance, repairs, - “support” staff, consumables and other daily operating expenses, drilling companies spend tens of millions a year operating each one of their drilling units.

In this example, I have estimated operating costs to be $47 million the first year the vessel is in operation. I have also decided to increased these operating costs 3% each year to take into account inflation.

Drydock Costs: Whether or not the shipping company will be able to get their new drillship into a dry dock or not is another question, but regardless, money will need to be budgeted for major service upgrades every 5 years. In this particular example, I decided to include a $5 million upgrade at the 5 year mark, $35 million upgrade during the 10th year dry dock service, and $10 million upgrade at the 15 year mark to keep the vessel among the most capable in the industry.

The following Excel sheet captures these costs:

Projected Revenue:

The market for 5th and 6th generation rigs is still very strong and new-build 6th generation drillships are still commanding $500,000 day rates. Hypothetically, lets assume that our fictitious drilling company scored a 10 year contract at $500,000 per day.

Let’s also assume that the drilling company could operate the vessel with a revenue efficiency of 93% (less than 7% downtime). This would result in projected annual revenues of $169,725,000 for the first 10 years.

Let’s also consider that the vessel will score a 10 year contract extension (at the end of the current contract) only this time at $657,500 per day. At the same revenue efficiency of 93% this will amount to a projected annual revenue stream of $223,200,000 per year (for the final ten years of the vessel’s “life”).

The projected revenue over the “life” of our fictitious drillship is included in the table below. I have also included the “cashflow” from each year which is simply the revenues from that particular year minus the yearly operating expenses from the Excel sheet above:

Using the NPV formula I mentioned above, I programmed the Excel sheet to calculate the NPV of the estimated cashflows for each year of the ship’s projected life. This NPV is the “converted” value of the cashflows in “today’s dollars”. As you’ll see in the total at the bottom of the spreadsheet, the value of the opportunity to invest in the new drillship is over $200 million dollars!

In other words, the investment in building the new drillship (based on our very basic assumptions) is worth $200 million more to shareholders over and above the “opportunity cost of capital”.  That is the growth and value shareholders are looking for.

Although our example drillship, contract, and expense and revenue projections are all fictitious, the principles remain the same. The promise of “riches” is why we’ve seen virtually every drilling company in the world expand the size of their ultra-deepwater drilling fleets with aggressive new-build programs.

We’ve even seen companies with virtually no connection to the oil and gas industry commission new-build drillships on “spec”.

Demand is still strong for these vessels but as more and more are built on “speculation” and enter the market, day rates will inevitably come down and the promise of “huge” investment returns (like those we just calculated) will likely disappear.

LONDON (Dow Jones)–The U.K. has awarded 46 new licenses to explore for oil and gas in the North Sea, the Department of Energy and Climate Change announced on its website Friday.

The awards, part of the country’s 26th offshore oil and gas licensing round, came as the U.K. handed out 144 licenses in total. Companies to snap up the new exploration blocks include Royal Dutch Shell PLC (RDSA.LN), Germany’s Wintershall AG and France’s GDF Suez SA (GSZ.FR).

“These further licenses have been subject to rigorous examination, and we are now satisfied that initial exploration can go ahead,” said Energy Minister Charles Hendry.

“These continued high levels of interest, and the award today of these licenses, gives me yet more reason to be optimistic for a prosperous 2012 for the U.K. oil and gas sector,” Hendry added.

-By Alexis Flynn, Dow Jones Newswires

At 1253 feet (382m) in length, and 384 feet (117m) at the beam, this massive ship will have a footprint twice as large as the Emma Maersk.  Eight diesel generators will provide 95MW of power to 12 azimuth-mounted thrusters and for all operational needs.

This ship was uniquely designed with the ability to deconstruct aging offshore oil production structures, particularly those found in the North Sea, as well as for high capacity pipelay operations.

USS Antietam and the USS Carl Vinson battlegroup (US Navy photo)

On the bow of the Pieter Schelte is a unique system that allows her to latch on to a topsides structure and conduct a 48,000 ton maximum lift to separate this structure from the supports below that reach down to the sea floor.  To put this in perspective, 48,000 tons is about 5 times as heavy as a Ticonderoga-class Cruiser.

Once the topsides removal is complete, the ship will then turn 180 degrees and a powerful array of high capacity cantilever cranes will lift the steel “jacket” truss off the bottom and lay it flat on the aft deck.  This system will have the capacity to lift even the largest steel structures in the North Sea, the location of her primary mission once commissioned in 2013.

As a dynamically-positioned pipelay vessel, the Pieter Schelte will have a 2,000 ton tension capacity, twice that of the Allseas Solitaire, the current world record holder for pipelay capacity.  She will have the capacity to lay concrete-coated steel trunklines nearly 6 feet in diameter from her stern.

Video Flyby Of The Pieter Schelte

Click here to view the embedded video.

Decommissioning An Oil Platform

Pieter Schelte Decommissioning of an oil rig

For more videos of the Pieter Schelte visit Allseas’ movie gallery. To view other offshore behemoths visit gCaptain’s Heavy Lift section.

If you’re not going to the show, but want to keep in the loop on what we’re up to, follow us on Twitter @gCaptain or on Facebook for the latest updates.

Hope to see you there!

- posted from my iPad at BWI

Efforts to recruit a director for the newly formed Bureau of Safety and Environmental Enforcement follows months in which offshore-drilling regulators have become the target of intense criticism from Capitol Hill lawmakers and energy industry representatives who accuse the regulators of stifling oil production and hurting the Gulf Coast economy.

Earlier this month, Rep. Jeff Landry (R., La.) reportedly accused federal regulators of acting like “the CIA and Gestapo,” prompting a heated exchange with Michael Bromwich, director of the Interior Department’s Bureau of Ocean Energy Management, Regulation and Enforcement.

The top slot at the safety bureau opened up following a massive overhaul of an Interior Department agency that used to oversee all aspects of offshore oil drilling: both the collection of revenue as well as the enforcement of safety standards. In the wake of the Deepwater Horizon oil, that agency–known as the Minerals Management Service–was accused of conflicts of interest and broken into three separate agencies.

The Interior Department announced Friday it had completed the reorganization of the Minerals Management Service. The safety bureau will regulate permitting and inspections, while the two other agencies will be responsible for revenue collection and leasing.

Speaking with reporters Friday to mark the occasion, Bromwich said some candidates have turned down offers to lead the bureau because they didn’t want to deal with the political heat that would likely accompany it.

“A couple of quite-qualified candidates specifically said they didn’t want any part of the politics that came with it,” Bromwich said. He added that he will serve as the temporary director until a permanent candidate can be found.

Bromwich, who was recruited last year to help oversee the reorganization of the Minerals Management Service, has often sparred with Capitol Hill lawmakers who accuse him of stalling oil production in the Gulf of Mexico.

Bromwich has had to defend the Obama administration’s decision to suspend deepwater drilling after the Gulf of Mexico oil spill and is frequently criticized for the pace at which the Interior Department approves permits for new drilling projects.

Bromwich has acted “with the patience of Job,” Interior Secretary Ken Salazar said Friday. “We do deal with some very difficult issues with Congress.”

One recent incident involved Louisiana Congressman Landry, who reportedly accused Interior regulators of acting like the “CIA and Gestapo” after visiting the department’s New Orleans office to ask about the status of certain permits. After having to wait in the lobby for 20 minutes, Landry said he was told top officials were not in the office and that he would have to return at another time.

The incident sparked a heated exchange between Landry and Bromwich in the following days.

Bromwich sent Landry a letter, saying Landry’s reference to the Nazi secret police was “simply unacceptable from anyone, but especially from a public official.”

Landry replied with a letter of his own, saying Bromwich was mischaracterizing his comments. “The people of South Louisiana sent me to Congress to do a job and part of that job is to provide oversight to ensure that taxpayer-funded offices are indeed completing the functions for which they were created,” Landry said.

-By Tennille Tracy, Dow Jones Newswires

ModuSpec BV and Scandpower AS, members of the Lloyd’s Register Group, are developing a new tool with origins from the nuclear power industry that may prove highly useful to subsea engineers, offshore drilling managers, and regulators.

Operational Risk Management (ORM) is the process that evaluates the likelihood of a casualty occurring while comparing it to its associated consequences. BOP Monitor, a new tool under development by Scandpower applies ORM principles in a highly specific manner to one of the most important, and highly complex systems on board a drilling rig, the blow out preventer.

Last year’s Deepwater Horizon disaster cast an enormous spotlight on blow out preventer technology because the one sitting atop the Macondo Well failed to accomplish its mission, and millions of gallons of oil spilled into the sea.   A one-in-a-million chance?  Perhaps.  In the decades since subsea blowout preventers have been used, countless have worked as-designed mitigating the disastrous consequences we all saw last summer.
As the industry moves toward the arctic however, failure of these systems is absolutely not an option and risk management is of utmost importance to operators and coastal states.

In an interview last week with Scandpower AS’ Technical Director, Inge Alme, he explained,

The BOP Monitor program is unique because it creates a BOP-specific Operational Risk Management profile while taking into account factors such as water depth, the reliability of each component within that BOP, and the brand of BOP being used.  Operators, regulators, and subsea engineers can now know in real-time, and with a much higher degree of certainty, the risk incurred whenever subsea issues are encountered.

In their press release, ModuSpec’s Chief Executive Officer Duco de Haan, elaborates:

 Present BOP risk assessments lack a consistent structure. As a result, decisions on whether or not to pull them for inspection and maintenance can be subjective and difficult to understand, particularly for senior management and regulatory bodies.

Liberian-flagged and DNV-classed, Scarabeo 9 is a semi-submersible drilling vessel recently built by Yantai Raffles.  It will be on contract by Repsol YPF for deepwater exploratory drilling off Cuba.  

WASHINGTON -(Dow Jones)- Oil spill commission co-chief Bill Reilly is heading to Cuba next week to help evaluate that country’s plans for developing its oil resources, Dow Jones Newswires has learned.

The trip represents an important development in a thorny situation that has U.S. lawmakers raising concerns about potential oil spills and oil experts pressing the Obama administration to grant exemptions under the decades-long embargo.

The trip, which will involve a delegation of U.S. oil-drilling experts and environmentalists, coincides with Cuba’s effort to develop its offshore oil resources as a way to wean itself off imports from Venezuela. U.S. officials believe Cuba’s waters could contain more than 5 billion barrels of undiscovered oil.

Cuba’s efforts to tap its offshore oil will get off the ground later this year, when a consortium led by Spanish company Repsol YPF S.A. (REPYY, REP.MC) is expected to begin drilling a well in more than 5,500 feet of water off the country’s northern coast. If Repsol finds oil, it could touch off a quick-moving race to set up production in Cuban waters.

The delegation to Cuba, involving the International Association of Drilling Contractors and the Environmental Defense Fund, is on a fact-finding mission to determine the country’s long-term plans for pursuing its oil resources and identify steps to ensure safety and environmental protection. They’re scheduled to depart Monday.

The process of oil drilling in thousands of feet of water is “inherently risky,” said Daniel Whittle, Cuba program director at the Environmental Defense Fund and a member of the delegation. “We believe it’s imperative that if and when Cuba drills, they get it right.”

Reilly, as co-head of President Barack Obama’s oil-spill commission, helped to draft a report earlier this year that recommended U.S. officials work with Cuba and Mexico to develop shared standards for drilling in the Gulf. The oil-spill commission ceased operations in March after completing its work.

Cuba’s effort to promote drilling in its waters is presenting a thorny situation for U.S. lawmakers, regulators and companies.

Among the loudest critics of Cuba’s plans are Gulf Coast lawmakers who are raising questions about the country’s ability to respond to oil spills and the risks of crude oil washing on U.S. shores. Rep. Vern Buchanan, a Florida Republican whose district faces the Gulf of Mexico, introduced a bill earlier this year to allow the Interior Secretary to deny U.S. oil exploration and development leases to companies that do business with Cuba.

“The United States is not going to see a drop of that oil,” said Max Goodman, a spokesman for Buchanan. “And we have learned from Deepwater Horizon that an oil spill can devastate a regional economy and pose long-term damage to our natural resources.”

Repsol will be drilling in waters that are deeper than those in which the Deepwater Horizon rig operated at the time it exploded last year. Repsol will be using a Chinese-built drilling rig that only recently left Singapore for Cuban waters. The rig is expected to arrive in November or December.

The rig, known as Scarabeo 9, was built to conform with the U.S. embargo and Repsol has said it will be following U.S. safety standards, Repsol representative Kristian Rix said.

“We are confident that we have the right personnel and materials to drill safely and successfully in the area,” Rix said.

If oil is discovered, Cuba has a greater chance of becoming less dependent on Venezuela for its energy needs. In 2009, the country produced roughly 50,000 barrels of oil a day from onshore and coastal wells, relying on imports to supply an additional 130,000 barrels to meet consumption levels, according to the Energy Information Administration.

Given the risks of an oil spill, oil and natural gas experts are urging the Obama administration to grant exemptions under the embargo to allow U.S. companies and experts to respond to a disaster. U.S. companies, such as Helix Energy Solutions, have been particularly aggressive in developing oil spill containment systems in the wake of the BP Plc (BP, BP.LN) spill.

Allowing U.S. companies and experts to respond to a Cuban spill would be in the U.S.’s best interest, given the proximity of the drilling to U.S. shores, said Jorge Pinon, former president of Amoco Oil Latin America and visiting research fellow at Florida International University.

“There is an experienced company doing the work [in Cuba]” Pinon said. “What we’re lacking is, in the case of an emergency, Repsol and the other operators will not be able to access the resources” in the U.S.

-By Tennille Tracy, Dow Jones Newswires

The Republic of the Marshall Islands (RMI) Maritime Administrator has today released the DEEPWATER HORIZON Marine Casualty Investigation Report (RMI Report).

In accordance with national and international requirements, the RMI Report has been provided to the Secretary General of the International Maritime Organization (IMO). The Maritime Administrator has also provided a copy of the RMI Report to the United States Coast Guard (USCG) and the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). The RMI Report may be downloaded in its entirety via this link.

EXECUTIVE SUMMARY       

On 20 April 2010 the Mobile Offshore Drilling Unit (MODU) DEEPWATER HORIZON (hereinafter, the “DEEPWATER HORIZON” or the “Unit”) was completing drilling operations at the Macondo well, Mississippi Canyon Block 252 OCS-G 32306 #1, oil exploration project in the Gulf of Mexico on the United States (US) Outer Continental Shelf (OCS) in preparation to temporarily abandon the well. During these operations, there was a loss of well control that resulted in a release of liquid and gaseous hydrocarbons, which culminated in explosions, fire, the loss of 11 lives, the eventual sinking and total loss of the DEEPWATER HORIZON, and the continuous release of hydrocarbons into the Gulf of Mexico. The flow was stopped on 15 July 2010 and the well declared sealed on 19 September 2010.

Pursuant to section 710 of the Republic of the Marshall Islands Maritime Act 1990, as amended (hereinafter, the “Maritime Act”), the United Nations Convention on the Law of the Sea, 1983 (UNCLOS), the International Convention for the Safety of Life at Sea, 1974, as amended (SOLAS), and the Code of the International Standards and Recommended Practices for a Safety Investigation into A Marine Casualty or Marine Incident (hereinafter, the “Casualty Investigation Code”), the Republic of the Marshall Islands Maritime Administrator (hereinafter, the “Administrator”) has conducted an independent flag State marine casualty investigation of the DEEPWATER HORIZON casualty. In conducting the investigation, the Administrator drew upon documents submitted to the US Department of the Interior and the US Department of Homeland Security Joint Investigation (hereinafter, the “Joint Investigation”) team, testimony before the Joint Investigation team, its own investigators’ findings, and, where necessary, outside experts. To assist in its understanding and analysis of engineering and technical aspects, the Administrator retained drilling, engineering, and fire science consultants whose reports, entitled Casualty Investigation of MODU DEEPWATER HORIZON: Fire Origin Investigation (hereinafter, the “Fire Origin Report”) and Report of the Loss of Well Control and Assessment of Contributing Factors for the Macondo Well Mississippi Canyon Block 252 OCS-G 32306 #1 Well (hereinafter, the “Well Control Report”), have been drawn upon in determining relevant details and conclusions regarding the casualty.2 This casualty investigation report contains findings of fact, conclusions, and recommendations, focusing on the marine operations of the Unit, which are the purview of the flag State. Although not regulated by the flag State, the industrial operations of the Unit are discussed, in so far as they are necessary to provide a complete picture of the casualty or where they may have impacted the overall safety of the Unit.

Pursuant to this investigation, the primary causal factor conclusions, non-causal factor conclusions, and recommendations are:

CAUSAL FACTOR CONCLUSIONS

Although the Administrator does not have oversight responsibility for drilling operations on the US OCS, based on its assessment of the evidence in the investigative record and the attached Well Control Report, the Administrator concludes that the proximate cause of the casualty was a loss of well control resulting from:

• deviation from standards of well control engineering;
• deviation from the well abandonment plans submitted to and approved by the Minerals Management Service (MMS); and
• failure to react to multiple indications that a well control event was in progress.

The above factors contributed to the substantial release of liquid and gaseous hydrocarbons, which culminated in explosions, fire, the loss of 11 lives, the eventual sinking and total loss of the DEEPWATER HORIZON, and the release of hydrocarbons into the Gulf of Mexico.

NON-CAUSAL FACTOR CONCLUSIONS

• Better communication and coordination between the flag State and the coastal State regarding inspections and surveys could help to ensure that both the flag and coastal States are aware of conditions or requirements that could affect the safety of MODUs and their personnel.
• The Unit withstood the forces of the explosions and resulting fire, providing a sufficiently stable and protected platform to facilitate the evacuation of 115 of the 126 persons on board.
• The electrical power failed at the time of the first explosion or immediately thereafter. The failure of the primary power source added to the confusion during evacuation and complicated evacuation of the Unit.
• The total loss of electrical power compromised the functioning of the fire suppression systems; however, any attempts at suppression would have been futile given the intensity and magnitude of the fire and the uncontrolled fuel supply. It is unlikely that any ship borne system would have been effective at extinguishing the fire onboard the DEEPWATER HORIZON.
• The Emergency Disconnect System (EDS) did not function as intended and the MODU was unable to disconnect. Without any ability to stop or reduce the flow of hydrocarbons, and without power for vital systems, the crew was forced to evacuate the Unit.
• There were instances of confusion regarding decision making authority during the casualty. While such instances highlight the fact that the integration of drilling and marine operations presents challenges for maintaining a clear command hierarchy, especially in emergency situations, there is no indication that any confusion as to the chain of command was a causal factor in the casualty.
• Ideally, the evacuation of a vessel occurs in phases. However, the speed at which the casualty progressed provided limited time for reaction, control, mitigation efforts, and response. That 115 individuals were able to safely evacuate the vessel is due in part to the robustness of the underlying regulatory system, including requirements for redundancy of life saving equipment, routine fire and emergency drills, and safety orientations for all visitors to the Unit.
• The proximity of the DAMON B. BANKSTON and the timely and effective response of its crew substantially contributed to the evacuation of the DEEPWATER HORIZON.

RECOMMENDATIONS FOR IMPROVEMENT

• It is recommended that a communication system be developed between the relevant flag and coastal State regulatory bodies to address issues regarding units operating within the coastal State’s jurisdiction.
• While provisions of the International Maritime Organization (IMO) Code for the Construction and Equipment of Mobile Offshore Drilling Units (hereinafter, the “MODU Code”), 1989 contributed to the safety and evacuation of the crew, specific provisions of the 2009 MODU Code should be reviewed in light of the casualty.
• It is recommended that all unit operators ensure that the initial orientation for new crew members, contracted personnel, and visitors includes a discussion of the respective roles and leadership responsibilities of the Master and the Offshore Installation Manager, including how those roles change based on unit operations and emergency conditions.
• While not regulated by the Administrator, it is recommended that the operators and regulators review and amend, as appropriate, emergency procedures for activating the EDS and maintaining the Blowout Preventer (BOP).

Additional findings, conclusions, and recommendations are contained in the body of the report. 

Mars Tensioned-Leg Platform (TLP), Image by Garve Scott-Lodge 

HOUSTON (Dow Jones)–Royal Dutch Shell (RDSA) said Thursday it has received approval from federal regulators to drill a new well at its Gulf of Mexico Europa field.

The permit will allow Shell, one of the largest producers in the Gulf, to return all of its five contracted drilling rigs to work, a company spokeswoman wrote in an email.

Shell and other companies slowed the pace of drilling in the deepwater Gulf of Mexico after the federal government imposed a nine-month drilling moratorium in the area following last year’s BP PLC’s (BP) Deepwater Horizon oil spill. The government resumed issuing permits in late February.

The approval Shell received Thursday came from the Bureau of Ocean Energy Management, Regulation and Enforcement for a new well at Europa, a subsea field in nearly 4,000 feet of water. Production from Europa is tied to Shell’s Mars tension-leg platform.

The bureau oversees oil and gas drilling in federal waters.

-By Isabel Ordonez, Dow Jones Newswires

The contract includes installation and tie-in of heavy lift structures in the Gorgon and Jansz fields. Project management and engineering will start immediately while the offshore operations are scheduled to start in 2013.

The Gorgon project is one of the world’s largest natural gas projects, and is operated by Chevron and is a joint venture of the Australian subsidiaries of Chevron, ExxonMobil Corp. (XOM), Royal Dutch Shell PLC (RDSA), Osaka Gas Co. Ltd. (9532.TO), Tokyo Gas Co. Ltd. (9531.TO) and Chubu Electric Power Inc.(9502.TO).

Shares Thursday closed at NOK143.80.

-By Katarina Gustafsson, Dow Jones Newswires