Malaysia's Oil, Gas Worker Needs to Rise amid Ambitious Growth Plans

Oil and gas production has been central to Malaysia's growth ever since oil was first drilled in Sarawak at the start of the 20th century. Given Malaysia's prolific hydrocarbon resources, it comes as no surprise to industry watchers that the government's focus will continue to be placed on developing the country's oil and gas sector moving towards 2020.

Global oil and gas production has grown by around 1.5 percent per year in the last decade driven by rising demand from developing countries, notably China, India and Southeast Asia, according to a report by the International Energy Agency (IEA) released in July 2012.

Oil demand in the developing world, said the IEA, will overtake that in industrialized countries for the first time this year, a tipping point in oil demand geography.

"Strong economic growth in Asia, the former Soviet Union and the Middle East has pushed up demand in these regions, while the Eurozone and the U.S. remain weak," the IEA report noted.

Meanwhile, a tighter balance of supply and demand is expected in both oil and gas markets by the middle of the decade, as demand growth catches up with supply infrastructure. Beyond 2014, the momentum for deepwater exploration – especially among emerging economies – is expected to markedly increase as easy plays among shallow waters become rarer, research group Douglas Westwood revealed in a July 2012 presentation.

Against Asia's structural shortage for hydrocarbons, in particular oil, it is no surprise that Malaysia – a country famed for its light, sweet crude produce – is placing a renewed interest on developing its oil and gas industry.

Malaysia's oil and gas policy, which historically has focused on maintaining its reserve base, has evolved in recent years. A roadmap published by the Malaysian government in July last year states that the country aims to achieve the following oil and gas-related goals:

Rejuvenate existing fields through enhanced oil recoveryDevelop small fields through innovative solutionsIntensify exploration activitiesBuild a regional oil and gas trading hub by 2020Unlock premium gas demand in the PeninsulaAttract multi-national corporations to bring a sizable share of their global operations to the country

The Malaysian government noted that in order to deliver on its long-term oil and gas goals, it needs to develop its manpower infrastructure. In its report, the government disclosed that the country, alongside with state-owned and private enterprises, will be looking to hire over 60,000 workers by 2020.

"A significant proportion of these jobs will be highly-skilled jobs, with an estimated 21,000 (40 percent) for qualified professionals such as engineers and geologists, with monthly salaries in the range of $1,618 to $3,236 (MYR 5,000 to MYR 10,000)," the report revealed.

The Malaysian government pointed out that the bulk of its hiring efforts will be targeted at the country's oilfield services segment, liquefied natural gas (LNG) exploration and trading sector and its small field development strategy.

In the case of the country's oilfield services sector, the Malaysian government remarked that no other country in the world comes as a close second to challenging Malaysia as an oilfield services hub.

"While there are dispersed pockets of activity, there is no clear hub elsewhere in the world. With a burgeoning domestic oil and gas industry, proximity to oil fields and a cost-competitive workforce, there is potential for Malaysian companies to first become domestic champions and then subsequently regional champions as they capture a larger share of the market," the report said.

As part of its transformation initiative, Malaysia is aiming to focus on attracting international oilfield service companies to relocate their global operations to the country and enter into joint ventures to move up quickly on the technological curve.

In line with its aim to grow the oilfield services sector, Malaysia anticipates that around 40,000 additional workers will need to be employed to support the industry.

The Malaysian government also laid out an equally strong mandate for the country's LNG sector. An intricate long-term employment blueprint has been weaved by Malaysia's leadership as the country looks to position itself as Asia's LNG hub for storage, trade and transportation for the commodity.

"For the first phase, which is to be commissioned by this year, a capacity of 3.5 million tonnes of LNG per annum has been planned (actual capacity, cost and timing will be determined by Petronas). Petronas will execute all elements of the end-to-end gas delivery including partial marketing of this imported gas," the report stated.

Like its oilfield services sector, Malaysia is banking on its cost advantage – over that of neighbor Singapore – to realize its LNG potential. The Malaysian government projected in its 2020 vision that the rise of country's LNG industry would provide the foundation for some 27,000 new jobs; the bulk of which is concentrated to support the construction of the fixed and floating elements of gas regasification and processing projects in Johor and Sabah-Sarawak.

In the small field development area, the spotlight is on developing the country's small risk contracts. The Malaysian government noted that a significant proportion of Malaysia's remaining petroleum resources are sited in fields with less than 30 million barrels of recoverable oil.

"Developing these fields in an economically attractive manner is often challenging, as they need the same expensive infrastructure as large fields, while the expected revenue streams are smaller due to the smaller reserve sizes," the government admitted.

As such, despite the relatively high price of crude, the small risk contract industry is characterized by smaller employment growth numbers when compared to the oilfield services and LNG regasification sectors.

While small risk contracts have much interest among international oil exploration companies, the industry's development has been slow amid strong differing viewpoints between Petroliam Nasional Berhad (Petronas) and international oil corporations.

Back in 2011, Petronas noted that it aimed to award four marginal fields per year. However, thus far, only the Kapal-Banang-Meranti and Balai fields have been dished out. This offers a plausible explanation for the country's conservation employment growth rate; the industry is expected to generate slightly below 400 new jobs by 2020.

But development in the small risk contracts sector could evolve rapidly in the near-term. Industry watchers agree that Petronas could ramp up its efforts on the small risk contracts front and look to award more contracts this year as it seeks to compensate for the shortfall of its development target in the previous years.

Quintella has reported on the upstream and downstream oil and petrochemicals markets from 2004. Email Quintella at quintella.koh@rigzone.com.

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Lawyer Says Transocean Failed to Train Drilling Rig Crews Properly

NEW ORLEANS - Transocean Ltd. failed to train its drilling rig crews properly and didn't maintain key safety equipment on the doomed Deepwater Horizon drilling rig, leading to the deadly 2010 explosion and oil spill, a lawyer representing Gulf Coast businesses said.

During opening statements of a trial over liability, Jim Roy, a lawyer for companies suing BP PLC, Transocean, Halliburton Co. and others, cited a string of prior incidents in Federal District Court that he said showed the rig owner was grossly negligent leading up to the accident.

Information about close calls on other rigs wasn't passed along, Mr. Roy said, adding that just a month before the April 2010 accident, the Transocean crew on the Deepwater Horizon failed to catch a sudden surge of natural gas from the well they were drilling, indicating the company had "a chronic problem."

Mr. Roy was the first lawyer to make an opening statement on the first day of the civil trial aimed at determining the degree of culpability BP and the other companies have for the disaster, which killed 11 workers and unleashed the worst offshore oil spill in U.S. history. A second trial, scheduled for the fall, will determine how much oil leaked into the Gulf of Mexico. Together, these cases will determine the size of fines companies face under the Clean Water Act, which could range as high as $17.6 billion.

BP, which hired Transocean and Halliburton to work on drilling its deep-water oil well, has argued the fines would likely be less than $5 billion. The company will get 90 minutes to put on its opening statement Monday afternoon.

Transocean, which presented its opening statement Monday morning, rebutted the claims against the company's rigs and its crews. The Coast Guard, federal safety regulators and BP's own management considered the Deepwater Horizon drilling rig "what 'good' looked like," said Brad Brian, a lawyer for Transocean. He outlined details of Transocean's safety systems, and emphasized that BP had primary responsibility for the design of the well and for final safety decisions.

"BP took a series of unconscionable risks with what it knew was an exceptionally dangerous well," Mr. Brian said.

Mr. Brian focused on a 10 minute ship-to-shore phone call between two BP engineers, Mark Hafle and Donald Vidrine, less than an hour before the explosion. Mr. Vidrine allegedly talked about odd results from a key safety test, results that Mr. Hafle noted didn't seem to be appropriate.

"In many ways, it's a microcosm of what BP did wrong on this well and why Transocean and its crew truly are victims of BP's misconduct," Mr. Brian said. Instructing the crew to go ahead with its work in the wake of these test results "was reckless, in utter and wholesale disregard of the facts."

Michael Underhill, the Justice Department's lead civil attorney in the case, also focused on that conversation as one of several places where the accident could have been prevented.

"That conversation we will show should have prevented the tragedy, the need for any of us to be in this courtroom today and for the next 3 months," Mr. Underhill said. "They had a conversation that could have saved eleven lives, saved the Gulf, saved the people of the Gulf from a catastrophe."

The government plans to "show that a long series of missteps and reckless decisions by BP taken together demonstrate willful misconduct," he said. "We will show that individual decisions made by BP standing alone constitute gross negligence."

BP has already agreed to pay more than $30 billion in fines, settlements and cleanup costs for the well blowout and the resulting Gulf of Mexico oil spill, including $4 billion to settle criminal charges related to the accident. Transocean has agreed to $1 billion in civil fines and $400 million in criminal penalties.

Witness testimony is expected to begin on the Tuesday, starting with Robert Bea, a professor of civil and environmental engineering from the University of California, Berkeley. He will likely be followed by Lamar McKay, chairman and president of BP Americas. A previously taped questioning of former BP chairman, Tony Hayward, will be played Tuesday.

Despite the start of the trial, settlement discussions are continuing, according to people familiar with the matter. The Justice Department and Gulf Coast states have considered offering BP a deal under which the company would pay $16 billion to settle civil claims. The settlement offer would cover potential fines owed by BP under the Clean Water Act, and payments under an environmental evaluation known as the Natural Resources Damage Assessment, these people said.

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

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Industry Groups Refute Concerns Over US LNG Export Benefits

Industry associations American Petroleum Institute (API) and the Western Energy Alliance (WEA) jointly called for the U.S. Department of Energy (DOE) to approve applications for U.S. liquefied natural gas (LNG) export terminals beyond the one application that has been approved so far.

In a conference call with reporters Monday, API and WEA officials countered comments by proponents of LNG export restrictions that exporting natural gas would drive up domestic gas prices and put U.S. manufacturers at a disadvantage, arguing that the United States was capable of expanding gas production to meet demand.

The call came as the public comment period ended for DOE's 2012 Liquefied Natural Gas export Cumulative Impact Study, conducted by NERA Economic Consulting for the U.S. Energy Information Administration. Both groups decided to take the opportunity to reply to comments received so far on the study.

"In analyzing the comments, we found none that provided sufficient credible information to undermine the study's basic premise that the overall U.S .economy would greatly benefit from LNG exports, nor any that convincingly make the case for DOE to deny export terminal licenses," WEA said in a Feb. 22 letter to DOE.

Officials noted that expanding U.S. production would benefit consumers by creating new jobs and economic growth for the United States Recent data shows an average 213,000 new jobs per year could be created from 2015 to 2035 and $700 billion in growth could be created in the chemicals and manufacturing industries due to increased natural gas production, Erik Milito, director of upstream and industry operations with API, said.

The increase in U.S. natural gas supply thanks to the shale boom undercuts the main argument of proponents for restricting exports, which is that DOE used outdated supply data in its analysis that said allowing exports would be beneficial, Milito noted.

"The most recent data from DOE confirms that supplies will be very robust. This implies that there is more than sufficient natural gas to meet domestic and export needs with little adverse impact on prices – and that the net economic benefits of allowing exports are even greater than earlier though," Milito added. "The critics simply didn't acknowledge what an energy juggernaut the shale gas revolution has become and that it is still growing.

Further, the DOE study focuses rigidly on production and price increases, with not enough study into the ability of producers to increase capacity. While gas activity has fallen off in certain dry gas basins such as the San Juan, Powder and Green River basins, more associated gas is being produced with oil in the Bakken and Permian plays, meaning that gas production can be increased in response to demand and keep gas prices down, said Kathleen Sgamma, vice president of government and public affairs with WEA, a group that represents over 400 exploration and production companies, mostly smaller producers with less than 15 employees.

Nineteen projects have either been approved or proposed for U.S. public lands that could create jobs and drilling activity if they are allowed to move forward. These projects also could substantially add natural gas production in the western United States, said Sgamma, who pointed out that the most recent study used data that underestimated U.S. gas production.

However, United States should take advantage of its "first-mover" advantage with the abundant shale gas supplies now available and move forward with LNG exports before the window of opportunity runs out, Sgamma commented.

"Other nations are starting to invest in American-developed horizontal drilling and hydraulic fracturing technology to develop their own reserves. Now is the time for the Obama administration to approve LNG export terminal licenses, rather than continuing to delay job creation and economic growth."

To date, DOE has approved one LNG export application for the Sabine Pass project in Louisiana. The facility is scheduled to begin exporting LNG in 2015. Milito said he believes that the United States won't see "unlimited and unfettered" exports, noting that the market will impose natural gas limitations on which projects moved forward following approval by DOE.

Last week, a group of U.S. senators including Jim Inhofe (R-Oklahoma), Mary Landrieu (D-La.) and Mark Begich (D-Alaska) urged DOE Secretary Steven Chu to support the NERA Economic Consulting Report on U.S. LNG exports, rebutting comments filed that expressed concerns over whether U.S. LNG exports would be in the U.S. public interest.

"For the United States to be a hub of cheap energy, it is imperative to pursue government policies that allow the private sector to make every energy resource as abundant, accessible and as versatile in its consumption as possible," the senators wrote in a Feb. 21 letter. "Achieving this objective requires that producers be allowed access to markets, and that consumers be allowed access to resources.

"Providing this access without bias for one source over another will encourage more widespread production of all energy resources. This will benefit the economy, as it will be accompanied by increased economic activity, job creation, and more widespread energy choices," the senators commented in the letter.

Proponents of restricting U.S. LNG exports include some U.S. manufacturing and petrochemical companies who argue that exporting gas would raise U.S. domestic prices, putting these companies at a competitive disadvantage versus companies from other countries. Some environmental groups who are opposed to hydraulic fracturing also have expressed opposition to U.S. LNG exports, saying that exporting gas would result in increased hydraulic fracturing activity and that NERA did not factor in environmental damage into the costs of allowing LNG exports.

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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Subsea 7 Wins Talisman Pipeline Contract

Oilfield services firm Subsea 7 announced Wednesday that it has been awarded a contract to install pipeline bundles at Talisman Sinopec Energy UK's Montrose Area Redevelopment Project.

The contract, valued at $285 million, will see Subsea 7 deliver two three-mile pipeline bundles that will tie back the Cayley field to the new bridge-linked platform (BLP) at the Montrose facility. The contract scope also includes the procurement, fabrication and installation of an 11-mile production pipeline, water injection pipeline, gas lift pipeline and control umbilical to tie back the Shaw field to the BLP.

Subsea 7 said that engineering and project management will begin immediately from the firm's Aberdeen office with offshore operations starting in 2014.

Steph McNeill, Subsea 7's Vice President for UK and Canada, commented in a statement:

"This contract award continues our long-standing business relationship with Talisman. The complexity of this project further illustrates our bundle system’s unique ability to offer a highly cost-effective single product which neatly integrates all necessary pipelines and control lines."

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Keppel O&M Secures Contracts from MTOPS, SMB Offshore

Keppel Offshore & Marine (Keppel O&M), through its subsidiaries – Keppel FELS Brasil and Keppel Shipyard – have secured two contracts worth $161 million (SGD 200 million) from repeat customers, the company disclosed late Tuesday.

Keppel FELS Brasil's contract is with MODEC and Toyo Offshore Production Systems (MTOPS) to integrate the topside modules of a floating production storage and offloading (FPSO) unit. The project will be carried out at BrasFELS, Keppel FELS Brasil's yard in Brazil.
The FPSO, a project by MODEC and its partner Schahin Group, has been chartered for operations offshore Brazil for 20 years.

Integration works for the FPSO will take place from 3Q 2014 to 3Q 2015. The completed unit will have a production capacity of 150,000 barrels of oil per day and storage capacity of 1,600,000 barrels of oil.

Keppel Shipyard has meanwhile been engaged by SBM Offshore to fabricate an internal turret for a newbuild FPSO, which will be installed in the Ichthys Field, offshore Western Australia. Inpex awarded SBM Offshore the contract to engineer, procure, fabricate and supply the turret in February last year. The contract also includes assistance during the integration of the turret into the FPSO as well as during installation on the field. Installation is slated to start in mid-2015.

Keppel Shipyard's work on the 6,800-tonne Ichthys FPSO turret is scheduled to complete by Q3 2014.

"We are pleased to be selected by our customers for repeat projects as these are strong affirmations of the quality of our services. BrasFELS and MTOPS' first FPSO project was delivered safely and 19 days ahead of schedule; the second project is underway and on track for delivery in 2Q 2014. Keppel Shipyard has collaborated with SBM Offshore on some 17 major conversion and fabrication projects," Keppel O&M's CEO, Tong Chong Heong, said in a statement.

Keppel Shipyard's ongoing projects for SBM Offshore are the conversion of FPSO OSX-2 for Brazil as well as modification and upgrading of FPSO N’Goma for Angola. SBM Offshore is also working with Keppel Singmarine on the newbuilding of a multi-purpose dive support construction vessel.

Quintella has reported on the upstream and downstream oil and petrochemicals markets from 2004. Email Quintella at quintella.koh@rigzone.com.

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DNV Inks Contract for LLOG's Delta House FPS

Det Norske Veritas (DNV) will classify LLOG Exploration Company LLC's Delta House floating production platform, which is scheduled to begin production in the deepwater Gulf of Mexico in 2015.

The U.S. Coast Guard will accept plan review and inspection functions conducted by DNV for the project as part of the unit's certification under Title 33 Code of Federal Regulations. The acceptance follows from a general acceptance given by the U.S. Coast Guard in 2007, and will provide owners and operators of offshore floating units a new option for classification and certification work.

Until 2007, legislation stated that the American Bureau of Shipping (ABS) was the only company that could classify floaters in the Gulf of Mexico, a DNV spokesperson told Rigzone. U.S. Coast Guard and legislative requirements were changed that year, but uncertainty has existed in the market as to whether it would really be straightforward to use anyone else but ABS, a DNV spokesperson told Rigzone in an email statement.

"Owners have expressed a strong desire for choice of classification society's for floating offshore installations in American waters and we know there are many owners, designers, operators and yards who would prefer to work with DNV, and this contract is proof that they can do so, confident of legal and regulatory approval," said Kenneth Vareide, DNV's director of operations for maritime in North America, in a statement.

Besides the associated benefits of free choice and competition, DNV's extensive research and development efforts means the company can bring deep, often new knowledge and competence to challenges facing the industry, the spokesperson said. For example, the company was the first the comprehensively address the risks associated with all the systems and software that are critical for offshore units, and often a case of unexpected delay and downtime, when not properly addressed.

With local capabilities and expertise, DNV is a well-established alternative and experienced partner for classifying floaters and complex projects in the Gulf of Mexico.

"We now look forward to address the industry's needs and desires for increased safety, reliability, cutting edge technology and, of course, reduced downtime," Vareide commented. "We are confident that both owners and regulatory agencies will benefit from this."

The company will carry out approvals for classification and verification work, and surveys related to activities in the United States. DNV also is the certified verification agent (CVA) for the Bureau of Safety and Environmental Enforcement for the structure, mooring and riser, which will be handled from DNV's Houston office.

DNV has carried out extensive verification and independent analysis for many Gulf of Mexico floaters over the past 20 years, including many high profile failure and accident investigations. The company has a wide portfolio of CVA and development projects for the Gulf of Mexico oil and gas industry, including the first U.S. Gulf floating production, storage and offloading system at the Cascade and Chinook field.

The design basis agreement for Delta House, as approved by the Coast Guard, is based largely on DNV's offshore rules for a floating offshore installation.

LLOG Exploration and partners last December approved the Delta House project, which will include a floating production system (FPS), an oil export line, a natural gas export line and a number of subsea systems. Development costs for the project are estimated at over $2 billion.

The FPS, which will be located in Mississippi Canyon Block 254 in approximately 4,500 feet of water, will have production capacity of 80,000 barrels of oil per day (bopd) and 200 million cubic feet per day (MMcf/d) of gas, as well as peaking capability of up to 100,000 bopd and 240 MMcf/d. The facilities are expected to process and transport production from six initial wells when commercial operations begin.

The facility will be capable of accommodating production from nearby fields, including LLOG's previously announced discoveries in Mississippi Canyon Blocks 300 and 431. It will have space for 20 risers, which will allow production from up to nine simultaneously producing fields with dual flowlines.

The Delta House FPS will be constructed using Exmar Offshore Company's OPTI-11000 semisubmersible hull design at Hyundai Heavy Industries Ulsan, South Korea shipyard. Audubon Engineering will design and procure the topsides equipment.

Once construction is complete, the FPS hull will be transported by Dockwise to Kiewit Offshore Services yard in Ingleside, Texas. Kiewit will manufacture and integrate the topsides with the hull. Intermoor will moor and install the FPS.

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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Edge Resources Spuds Saskatchewan Well

Edge Resources Inc. has moved a drilling rig and spud the first of several planned drilling locations in Primate, Saskatchewan.

Resulting from a recently-shot 3D seismic program, the Company has discovered what it believes to be three new oil pools in an area the Company calls Asset East. The rig has been brought in to start the development program of Asset East and is drilling the first of what the Company expects will be many development and delineation wells drilled into these oil pools.

The Company believes these new pools hold a significant amount of reserve value and net present value.

Log and production information from the initial wells can be used to define a much larger developmental drilling program, which could require up to an additional 80 vertical locations to fully develop the pools.

Brad Nichol, President and CEO of Edge commented, "We are excited to continue upon our initial drilling and seismic successes resulting in the initial pool discoveries. Now the team is focused on the longer-term development of Asset East in Primate. Along those lines, we are also pleased to have received final approval for a water disposal program in Asset East, which fits very nicely into the long-term development plan for these pools."

As a key component to the full development plan for Asset East, the Company is very pleased to have recently received approval to inject produced water, if required, into a nearby existing wellbore on Company-owned lands. If water disposal is required, this approval is anticipated to drastically reduce the cost of water handling as the field is more fully developed.

The Company has a 100 percent working interest in all of their Primate, Saskatchewan properties - a total of 20 gross/net sections (12,800 acres).

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Sunset Industries Notes Availability of Drilling Performance Fluid

Sunset Industries confirmed an immediate availability worldwide of its Drilling Performance Fluid because of a strategic relationship that has been accepted from a top 3 company oilfield company for global distribution.

"As of 2/18/13, operators can immediately order our product and increase profitability with all wells worldwide," said Mike Long, CEO at Sunset Industries.

Many operators in the United States have already benefited from this cutting edge Drilling Performance Fluid. Recently a top U.S. operator used the product in the Granite Wash with a direct comparison wells that were 110 feet apart. Well #1 was drilled straight to KOP with no torque issues. The Drilling Performance Fluid was called in for use because Well #2 was approaching max torque limits shortly after intermediate casing due to a 12 degree tangent, starting at 500 feet. At this time it appeared that the well could not be completed.

Well #1 had no Drilling Performance Fluid and Well #2 had the product in the system at 3 percent concentration. Results from well #2, they finished the curve 54 percent faster, there was 37 percent reduction in torque, from end of curve a 12 percent increase in ROP, in addition they saved 2 Drill Bits & 2 Trip Outs.

With over 150,000 in savings a company spokesperson said, "We would not have been able to complete this hole without the Pro One Drilling Performance Fluid." (Case studies available upon request)

The Feb. 18 update is driven by customer feedback and is part of Sunset Industries' commitment to deliver the latest product updates and competitive enhancements.

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ConocoPhilips, Canacol to Explore for Colombian Shale Oil

BOGOTA - Canacol Energy Ltd., a Calgary, Canada, firm that operates in Colombia, said Wednesday it will explore for shale oil with ConocoPhillips in Colombia's Middle Magdalena basin.

Under the terms of the deal, ConocoPhillips will pay $13.5 million in cash and carry the cost of the drilling, completing, and testing of up to 13 wells.

The deal signals Colombia's growing appeal as an attractive place for oil and gas companies to do business in South America.

In a statement, Canacol said the agreement between the two companies calls for exploration and potential development of the Santa Isabel contract, one of five contracts that Canacol has interest in totaling 334,000 net acres "that expose [Canacol] to a potentially large unconventional shale oil play as supported by recent drilling results."

Texas' ConocoPhillips will get 70% of any shale oil found in the deeper areas while Canacol would retain the other 30% and keep 100% of the rights of shallower reservoirs.

The ConocoPhillips deal adds to partnerships Canacol has with two other major international oil companies, the local units of ExxonMobil Corp. (XOM) and Royal Dutch Shell PLC (RDSA).

Analysts in Colombia quickly praised Canacol's latest partnership.

"We think this is a brilliant move for Canacol," said Celfin analysts in a research note. "It is a large carry that allows the company to de-risk the block at no real cost and still allows it to have full control over anything they find that is small enough to fit in their budget."

Canacol's shares were up more than 4% Wednesday morning. Shares of ConocoPhillips were up less than 1% at $58.18 Wednesday morning.

For ConocoPhillips, an exploration and production company with market capitalization of $70 billion and operations all over the world, the venture is "not a needle-mover," Raymond James analyst Pavel Molchanov said.

But it does highlight growing interest in oil exploration in Colombia, where daily crude oil output grew by about 40% from 2009 to 2011, according to the U.S. Energy Information Administration, compared to meager growth or flat production in countries such as Venezuela and Ecuador, which produce much more oil.

In the last year, ConocoPhillips has announced plans to shed nearly $12 billion in assets, including some in Nigeria, Algeria and Kazakhstan to focus its spending on North American shale development.

"They absolutely need the money" from asset sales, Mr. Molchanov said. "But, it's still a multinational company, operating in over a dozen countries, and certainly Colombia on an all-in basis, is a relatively appealing place to invest."

At a gathering of the World Affairs Council of Houston last week, ConocoPhillips Chief Executive Ryan Lance highlighted Colombia's business climate as a bright spot in South America and a sign of Venezuela's waning influence in the continent.

ConocoPhillips and Exxon Mobil have pending disputes with Venezuela relating to the country's nationalization of oil assets in 2007, and ConocoPhillips no longer works in Venezuela. The company's only other operations in South America are in Peru, but it announced last year that it would not continue exploring there.

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

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