Monthly Archives: June 2012

GoM Lease Sale: Apache Expands Presence in Gulf of Mexico

Apache Corporation announced it was the high bidder on 90 shelf and deep water blocks in the Central Gulf of Mexico offshore lease sale held by the Bureau of Ocean Energy Management (BOEM) in New Orleans.

Of the 56 companies submitting bids for Gulf of Mexico acreage, Apache Corp. was ranked No. 1 overall for its 61 high bids on the shelf, while Apache Deepwater LLC, the company’s deep water arm, was ranked No. 4 overall with 29 high bids.

The sum of the combined high bids was nearly $96 million gross.

“We’re excited about these blocks and our expanding presence in the Gulf of Mexico,” said G. Steven Farris, Apache chairman and chief executive officer. “The Gulf of Mexico is integral to Apache’s long-term growth. The shelf provides some of the best margins, highest returns and most free cash flow, and the deep water has some of the best exploration potential of any region in our global portfolio.”

Bidding on acreage in the shelf was focused on areas where Apache is acquiring proprietary seismic data, along with moderate to deep exploration prospects based on recently acquired and reprocessed seismic data. Successful deep water bids were focused on Pliocene and Miocene trends where Apache has acquired a significant seismic data base. Deep water bid partners included Stone Energy, Samson, Noble, Repsol, Nexen and Ecopetrol.

“This was a very robust lease sale with premium acreage,” said Jon Jeppesen, executive vice president of Apache’s Gulf of Mexico regions. “These blocks strengthen our position on the shelf and in the deep water. In both areas, Apache has the fiscal wherewithal, technical prowess and experience to capture the value of these opportunities.”

The shelf and deep water Gulf of Mexico currently represents 15.5 percent of Apache’s overall daily production.

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Six New Leases for EPL in Central GoM Lease Sale (USA)

Energy Partners, Ltd., a U.S. based oil and gas exploration and production company announced was the high bidder on six leases at the Central Gulf of Mexico Lease Sale 216/222 held yesterday in New Orleans, Louisiana.

The six high bid lease blocks cover a total of 27,148 acres on a net and gross basis and are all located in the shallow Gulf of Mexico Shelf within the Company’s core area of operations. EPL’s share of the high bids totals $7.0 million.

Gary C. Hanna, EPL’s President and Chief Executive Officer commented, “This lease sale was a long awaited one, and we are pleased that we were successful with high bids within our core areas and targeted region. Consistent with our acquisition and organic growth strategy, the leases contain oily prospects that enhance our existing portfolio and were identified with the aid of our regional study that kicked off earlier this year. The six leases include three leases within the Main Pass area, two within the West Delta area, and one adjacent to our South Timbalier 41 field.”

The Central Gulf of Mexico oil and gas lease sale attracted $1,704,500,995 in high bids for tracts on the U.S. outer continental shelf offshore Louisiana, Mississippi and Alabama. Yesterday’s highest bid on a tract was $157,111,000 submitted by Statoil Gulf of Mexico LLC for Mississippi Canyon, Block 718.

Secretary of the Interior Ken Salazar said that the sale, was good news for American jobs, good news for the Gulf economy, and would bring additional domestic resources to market.

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U.S. Gulf of Mexico Oil and Gas Lease Sale Attracts USD 1.7 bln in High Bids

Yesterday, the Department of the Interior took the latest step as part of President Obama’s all-of-the-above energy strategy to expand safe and responsible domestic energy production, holding a 39 million acre lease sale in the Gulf of Mexico.

Secretary of the Interior Ken Salazar announced that the Central Gulf of Mexico oil and gas lease sale attracted $1,704,500,995 in high bids for tracts on the U.S. outer continental shelf offshore Louisiana, Mississippi and Alabama. A total of 56 offshore energy companies submitted 593 bids on 454 tracts covering more than 2,402,918 acres. The sum of all bids received totaled $2,602,563,726.

The lease sale builds on a series of actions taken by the Obama administration, including additional lease sales for both onshore and offshore areas for oil and gas development, to meet the President’s direction to continue to expand safe and responsible production of America’s important domestic resources.

“This sale, part of the President’s all-of-the-above energy strategy, is good news for American jobs, good news for the Gulf economy, and will bring additional domestic resources to market,” said Salazar, who opened the sale. “When it comes to domestic production, the President has made clear he is committed to expanding oil and natural gas production safely and responsibly, and today’s sale is just the latest example of his administration delivering on that commitment. The numbers speak for themselves: every year the President has been in office, domestic oil and gas production has increased, foreign imports of oil have decreased, and we are currently producing more oil than any time in the past eight years.”

The Central Gulf of Mexico Lease Sale 216/222, conducted by the Bureau of Ocean Energy Management (BOEM), offered more than 39 million acres for oil and gas development on the U.S. Outer Continental Shelf. The acreage included 7,434 tracts from three to more than 230 miles off the coast, in depths ranging from 10 to more than 11,200 feet (3 to 3,400 meters). BOEM estimates the economically recoverable hydrocarbons that could be produced as a result of the acreage offered ranges from 0.8 to 1.6 billion barrels of oil and 3.3 to 6.6 trillion cubic feet of natural gas.

The sale builds on the successful Western Gulf of Mexico lease sale held by BOEM in December 2011 that made available more than 21 million acres – equal to an area the size of South Carolina – and attracted more than $337 million in high bids and included 20 companies submitting 241 bids on 191 tracts comprising over a million acres offshore Texas. In 2010, DOI offered nearly 37 million offshore acres to industry for oil and gas leasing.

“Before moving forward with Sale 216/222, we conducted a rigorous analysis of the environmental effects of the Deepwater Horizon oil spill on the Central Gulf of Mexico,” said BOEM Director Tommy P. Beaudreau. “We have also continued a number of lease terms designed to ensure fair return to the American people and provide innovative incentives to promote diligent development of our nation’s offshore oil and gas resources.”

Yesterday’s highest bid on a tract was $157,111,000 submitted by Statoil Gulf of Mexico LLC for Mississippi Canyon, Block 718. Shell submitted the highest total amount in bonus bids, $406,594,560 on 24 tracts.

Lease terms for both sales included escalating rental rates to encourage faster exploration and development of leases as well as shorter lease terms for shallower water in order to encourage timely development. BOEM has increased its minimum bid requirement in deepwater to $100 per acre, up from $37.50 in previous Central lease sales. Rigorous historical analysis showed that leases that received high bids of less than $100 per acre have experienced virtually no exploration and development activities.

Lessees will have to comply with a series of important environmental stipulations, including requirements to protect biologically sensitive features, as well as marine mammals and sea turtles, and employ trained observers to ensure compliance and restrict operations when conditions warrant. These terms will help ensure an appropriate balance of responsible resource development with protection of the human, marine and coastal environments.

Each high bid on a tract will now go through a strict evaluation process within BOEM to ensure the public receives fair market value before a lease is awarded. This is the final Gulf Lease Sale scheduled in the current Outer Continental Shelf Oil and Gas Leasing Program: 2007-2012.

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USA: Statoil Secures 26 New Leases in Gulf of Mexico

Statoil was the high bidder on 26 leases in the first lease sale in the Central Gulf of Mexico since March of 2010.

With the addition, Statoil will control more than 350 leases in the Gulf of Mexico, further securing its significant leaseholder position

“We are very pleased with today’s outcome,” says Erik Finnstrom, senior vice president of Exploration for Statoil in North America.

“This addition of leases allows us to further build upon our broad-based strategy for exploration in the Gulf of Mexico and further upgrades our core position in this prolific and proven basin.”

As the world’s largest offshore operator and a leader in subsea technology, Statoil has been a partner in several major discoveries, including Jack, St. Malo, Julia, Vito and Logan.

“The lease additions underscore our commitment to increased investment in North America, which we see as a core region for long-term growth. Our strategy involves acquiring prospects across a full range of plays – from those at the frontier level to very mature, drill-ready plays,” Finnstrom says. “Statoil’s growth in North America has been methodical, based on best practices and technological innovation honed from operating for 40 years in some of the world’s harshest offshore regions.”

Statoil has six producing fields and has eight fields under development. At the moment the company is drilling the Bioko prospect in the central Gulf of Mexico region and plans to drill two to three more wells within the next 12 months offshore Gulf of Mexico, while also participating in an additional two to three wells drilled by its partners.

Statoil is the operator of three of 2011’s 10 largest oil and gas discoveries globally and has a strong safety and environmental record. The company has been active in North America for 25 years and, over the six years since it began operations, has acquired a broad portfolio with offshore and onshore assets in Canada and the U.S.

The lease sale on June 20 was conducted by the Bureau of Ocean Energy Management (BOEM).

Statoil’s winning bids are subject to review and final approval by the BOEM. This may take up to 90 days.

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Brazil government fails to benefit blocking oil firms

Posted on June 21, 2012 at 6:41 am by Bloomberg

International oil companies looking to start exploring Brazil, home to the largest discoveries in the past decade, can’t get near the crude.

Brazil has repeatedly delayed the sale of exploration areas since 2007, leaving Exxon Mobil Corp. (XOM) and Royal Dutch Shell Plc (RDSA) shut out of an offshore area that holds at least $5 trillion of oil. Meanwhile Petroleo Brasileiro SA (PETR4), the state-run company that pumps more than 90 percent of the country’s crude, is struggling to develop deposits it has already found. Petrobras’s output grew 1.5 percent in 2011, the slowest pace in four years.

Companies including Total SA (FP) have accelerated exploration off the coast of West Africa, where the geology is similar to Brazil and which holds large discoveries in deep waters. OGX Petroleo & Gas Participacoes SA, controlled by billionaire Eike Batista, began exploring in Colombia amid delays in offering new exploration tracts in Brazil.

“Brazil is someplace where we would like to be more present; at the same time we are in 130 countries, it’s not one against the other, it’s one plus,” Total Chief Executive Officer Christophe de Margerie said in a June 18 interview in Rio de Janeiro. “I hate to say it but if it doesn’t work it doesn’t work. We would like it to work.”

Petrobras this month increased its five-year spending plan 5.3 percent to $236.5 billion, the biggest in the oil industry, to develop deposits in waters as deep as 2,800 meters (9,200 feet) and trapped under a layer of salt.

Price-to-Earnings

Petrobras trades at 6.81 times its estimated 2013 earnings, compared with a ratio of 9.74 for Exxon, 7.12 for Shell and 6.28 for Total, according to data compiled by Bloomberg.

Revenue at the Brazilian producer totaled $150.7 billion in the trailing 12 months, less than Exxon’s $442.9 billion, Shell’s $480.2 billion and Total’s $236.2 billion.

While a legislation change in 2007 put Petrobras in charge of all new contracts in the so-called pre-salt area off Brazil, the company hasn’t been able to extract oil fast enough to meet targets. Petrobras cut its long-term production guidance by 11 percent to 5.7 million barrels a day in 2020. Output will remain within 2 percent of 2011 levels until 2014, it said on June 14.

The lack of new exploration areas in Brazil has encouraged some companies to concentrate on other regions such as offshore Africa, where Tullow Oil Plc (TLW) and Cobalt International Energy Inc. (CIE) have made discoveries in deep waters. Last year, Anadarko Petroleum Corp. (APC) announced plans to sell all its Brazil blocks, granted before the 2007 legislation change, as it boosts investment in natural-gas projects in Africa.

Bid Rounds

“The absence of bid rounds is affecting all oil companies in Brazil,” Joao Clark, the head of Ecopetrol SA (ECOPETL)’s Brazilian operations, said in an April 17 interview in Rio de Janeiro. “We need new blocks, we have to improve our portfolio.”

Exxon quit its only Brazilian block this year after drilling three dry holes in deep waters, Patrick McGinn, a company spokesman, said by e-mail from Irving, Texas. The explorer is seeking more opportunities in the country, he said.

Petrobras is failing to meet output goals after new offshore wells didn’t compensate for declines at older fields. That jeopardizes its 2020 target. Brazil is counting on the company to provide national energy self-sufficiency to meet demand from a growing economy. Petrobras pumped 93 percent of the country’s oil and 99 percent of its gas in April.

Pre-Salt Zone

Foreign producers including Exxon and Total, with little acreage in Brazil, are seeking to eat into that share as fields dwindle in other areas such as the North Sea and Alaska’s North Slope. Brazil hasn’t auctioned any offshore permits since before announcing the potential of the pre-salt zone in 2007 and hasn’t sold any blocks at all since 2008, when it sold tracts on land.

“I understand quite well the anxiety of those companies,” Petrobras Chief Executive Officer Maria das Gracas Silva Foster told reporters in Rio on Feb. 13, the day she was promoted to the role. “For them it might be really important. For Petrobras, it makes no difference. We have a lot of work to do.”

Brazil probably won’t offer any areas in the region until 2013 because lawmakers are debating how to distribute future revenues, Marco Antonio Almeida, the Energy Ministry’s oil and gas secretary, said in a May 3 telephone interview from Brasilia. The pre-salt auctions will only occur after Congress votes on how to distribute the royalties from future output, the Energy Ministry said in an e-mailed response to questions.

Political Wrangling

The combination of political wrangling, requirements to buy locally built equipment and Petrobras’s budget constraints may even push new rounds to 2014 at the earliest, according to Christopher Garman, a Latin America analyst at Eurasia Group.

“The sentiment within the upper levels of government is they already have their hands full,” Garman said by phone from Washington. “What is really hurting the decisions of international oil companies to stay is the lack of a pipeline of new opportunities.”

Petrobras is required to have a minimum 30 percent stake in new pre-salt blocks. That means the Rio de Janeiro-based company can sign contracts before knowing who it will work with, making it hard to set up the auctions, Almeida said. “It’s a situation that doesn’t exist anywhere else in the world,” he said.

The lack of auctions has put a premium on existing permits. Companies that bought exploration areas before the discovery of Lula — the field previously known as Tupi, which was the Americas’ largest oil discovery in more than three decades — have seen the value of those areas increase as a result of oil- price gains and scarcity of acreage, Peter Gaw, head of oil, gas and chemicals at Standard Chartered Bank, said in an interview.

BG, Repsol

BG Group Plc (BG/) owns 25 percent of Lula, while Portugal’s Galp Energia SGPS SA (GALP) has a 10 percent stake. Repsol SA owns 25 percent of a neighboring block. Their properties, purchased years before anyone knew what they were worth, have since attracted global peers to the south Atlantic.

China Petrochemical Corp., Asia’s biggest refiner, has agreed to invest $12.3 billion to become a minority partner with Repsol and Galp in Brazil. BP Plc (BP/), who skipped the first pre- salt auctions, paid Devon Energy Corp. $3.2 billion last year for nine blocks in the country.

Petrobras doesn’t need to worry about the timing of new sales because oil will only gain in value in coming decades, Silvio Sinedino Pinheiro, elected to the company’s 10-member board by workers this year, said in an April 11 interview at its headquarters.

“Here at Petrobras we talk a lot about if it makes more sense to sell now at $100 a barrel, or sell in 30 years when it costs $200 a barrel,” he said.

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No relief for natural gas producers as Apache’s Kitimat plant delayed

Courtesy of Apache Canada Ltd.
An artist’s rendering of the proposed Kitimat Apache Canada’s LNG facility, which is now delayed for another year

Claudia Cattaneo Jun 20, 2012 – 6:47 PM ET
Last Updated: Jun 21, 2012 7:46 AM ET

Beleaguered natural gas producers in Western Canada are going to have wait a little longer for relief from severely depressed prices. Janine McArdle, the senior executive in charge of the Kitimat LNG project at Houston-based Apache Corp., said the facility’s planned startup will take an extra year as the company continues to look for firm contracts with buyers in Asia.

Apache’s proposed natural gas liquefaction plant on the northern British Columbia coast, which it owns with Encana Corp. and EOG Resource Inc., would be the first in line to ship large quantities of LNG to Asia.

The first cargo is now expected to leave Canada in 2017, a year behind the latest plans. The project has regulatory approval, but Apache needs to be sure it has a market for the gas and that the project is economic before taking a final investment decision, Ms. McArdle, senior vice-president for gas monetization at Apache, North America’s largest oil and gas independent producer, said Wednesday.

Construction of a 10-million tonnes a year plant would then take 50 to 60 months.

“We are moving as quickly as we possibly can given that Canada is new to these buyers, and we are relatively new to the buyers as Apache,” she said on the sidelines of an industry conference.

“We have been talking to multiple markets simultaneously and there is a lot of interest. I always have to remind people that these are 20, 30-year marriages. These things don’t happen overnight.”

Next in line is Royal Dutch Shell PLC’s B.C. LNG project, which is slated for startup in 2019. Shell gave the tentative go-ahead to the project last month with three Asian partners that will secure Canadian gas has customers — PetroChina, Mitsubishi Corp. and Korea Gas Corp. However, the project has yet to obtain regulatory approval.

Related

A handful of other projects are also in various planning stages, but they are further behind.

It’s a tense time for Western Canadian natural gas producers, who are watching closely progress on LNG facilities on the B.C. coast so they can start monetizing reserves already found and look for new ones. The facilities will enable exports to Asia and help alleviate a massive shale supply glut in North America that has depressed prices to 10-year lows.

Asian demand for LNG is expected to increase to 35 billion cubic feet a day by 2020, from 20 bcf today, said Ed Kallio, director of gas consulting at Ziff Energy Group, a Calgary-based gas forecasting firm. He expects demand to outstrip supply in Asia by 2016/2017.

The good news is that there is plenty of gas to keep the projects full. Apache announced last week that it discovered in the Liard Basin a new shale gas field containing as much as 48 trillion cubic feet of recoverable natural gas which it characterized as one of the world’s best.

The find motivates Apache to develop an alternative market for Canada, Ms. McArdle said.

It also further boosts Canada’s 500-trillion cubic feet of natural gas reserves, a number that has ballooned in recent years thanks to shale discoveries such as the Horn River, the Montney and the Cordova, all in British Columbia. To put it in context, the now-shelved Mackenzie Gas Project was underpinned by six trillion cubic feet of reserves in the Mackenzie Delta. The number seemed immense before shale gas was unlocked.

Mr. Kallio, who also spoke at the conference, said it will take a lot more than LNG exports to restore balance to the natural gas market and Western Canadian producers will be stuck in a low-price environment for several years. Demand will have to increase, and supply will come down as production of liquids-rich natural gas runs out of steam with weakening of liquids prices, as drilling promoted by land terms tapers off, and if producers do their part by being more disciplined, he said.

“We had such a rush and we had a bunch of cowboys out there, including Chesapeake [Energy Corp.] and Encana that drilled like crazy, [because] they had nice hedges on through the end of this year. But they have very little hedged next year, and that is why they are selling assets — they are selling fingers, toes, kidneys, prized assets to get the cash flows up” and hang in until the next rising market, Mr. Kallio said.

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Natural Gas: Where Endless Money Went to Die

Wednesday, June 20, 2012 at 4:17PM

The fiasco that is playing out in the natural gas industry doesn’t happen often in a free market, and when it does happen, it’s usually short—and brutal for all involved: namely, prices that are way below production costs. In most industries, hedging strategies might get market participants through the period, while unhedged production, a money-losing activity, gets slashed. If it lasts long enough, it causes a shakeout where less efficient or poorly capitalized producers, and their investors, get wiped out. It’s all part of the capitalist system that weeds out weaker elements through occasional sweeps of creative destruction.

As shortages crop up on the horizon, prices return to sustainable levels, and occasionally spike to once again unsustainable levels. For the survivors, or for lucky new entrants, the next step in the cycle has begun.

Alas, thanks to the Fed’s zero-interest-rate policy and the trillions it has handed over to its cronies since late 2008, the sweeps of creative destruction have broken down. Instead, boundless sums of money have been searching for a place to go, and they’re chasing yield when there is none, and so they’re taking risks, any kind of risks, in their vain battle to come out ahead. The result is a stunning misallocation of capital to the tune of tens of billions of dollars to an economic activity—drilling for dry natural gas—that has been highly unprofitable for years. It’s where money has gone to die. What’s left is debt, and wells that will never produce enough to make their investors whole. For that whole debacle, read…. Capital Destruction in Natural Gas.

But the money has dried up. And drilling for natural gas is collapsing. Last week, there were only 562 rigs drilling for dry natural gas—the lowest number since September 1999. A dizzying downward trajectory:

 

Producers, if at all possible, are switching to drilling for oil and natural gas liquids (priced like oil), still a profitable activity. Thus, capital is now being channeled to where it can make money. Drilling for dry natural gas will continue to decline as the long delayed sweep of creative destruction is scouring the industry.

The largest producer, ExxonMobil, given its monumental size and worldwide focus on oil, will weather the fallout just fine. But the second largest producer, Chesapeake Energy, is struggling. It’s trying to dump assets to raise cash to deal with its mountain of decomposing debt. Other producers that haven’t diversified away from dry natural gas are in a similar quandary. And at current prices, it’s going to be bloody.

At $2.53 per million Btu at the Henry Hub, the price of natural gas is up 33% from the April low of $1.90 per million Btu—a number not seen in a decade. But even if it doubled, it would still be below the cost of production. And if it tripled, it might still be below the cost of production for most producers. That’s how mispriced the commodity has become.

Misallocation of capital, and the resulting overproduction, is only part of the problem. The other part of the problem is horizontal fracking itself—a drilling method that extracts gas from shale formations. With nasty economics. It’s an expensive method. And once drilled, the well suffers from steep decline rates; after a year or a year-and-a-half, only 10% of the original production might still come to the surface.

The breakeven price for natural gas under these conditions—and it differs from well to well—is still partially theoretical since horizontally fracked wells have not yet gone through their entire lifecycle. Here is a detailed discussion and pricing model. The short answer: over $8 per million Btu. Even if that number is off, at the current price of $2.53 per million Btu, the industry is still near its point of maximum pain.

There are consequences. Power generators, having switched massively from coal to natural gas, are driving up demand. And production has finally seen a bend, a small one, in the curve that had set new highs month after month. Now, it’s declining. There is a lag between dropping rig count and production. The rig count estimates how many new wells are being drilled. Even if it dropped to zero next week, production would not immediately be impacted because the current wells would continue to produce. Production would then taper off as a function of decline rates per well—and in fracked wells, that lag is expressed in months, not years.

While the US doesn’t yet have LNG terminals to liquefy and export natural gas—in the global markets, LNG fetches mouthwatering prices between $10 and $15 per million Btu—it does have a pipeline to Mexico. According to BENTEK Energy (via the EIA), pipeline exports to Mexico hit 1,867 million cubic feet per day, a record in the seven plus years that BENTEK has been tracking it (by comparison, Chesapeake Energy produces about 2,575 MMcf/day).

 

Rising demand and exports are slamming into declining production. What was a record amount of natural gas in storage is coming down rapidly. Fears that storage would reach capacity towards the end of the injection period in the fall, and that natural gas would have to be flared, thus reducing its price to zero, seem ridiculous now. But prices, if they stay in the current ballpark, will continue to demolish producers, drive them away from dry natural gas, and cause financial bloodshed.

Until shortages appear on the horizon. But then, production can’t be ramped up quickly, regardless of what the price might be. Expect a spike and more mayhem, but this time in the other direction.

And oil, which has experienced a phenomenal boom in drilling? In North America, the range of oil qualities and a raft of infrastructure nightmares are wreaking havoc with record price differentials, writes energy expert Marin Katusa in his excellent…. Oil Price Differentials: Caught between the Sands and the Pipelines.

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Chevron Acquires Offshore Suriname Acreage

Chevron Corporation announced that its wholly owned subsidiary Chevron Global Energy Inc. (Chevron) will be assigned a 50 percent working interest in Blocks 42 and 45 offshore Suriname through an agreement with Kosmos Energy.

Under the agreement, Kosmos will have a 50 percent working interest and remain operator of both blocks until the end of the exploration phase. Chevron will assume the remaining 50 percent working interest and will be the operator following any commercial discoveries.

“This agreement enables us to explore for new resources in this frontier basin,” said George Kirkland, vice chairman, Chevron Corporation. “These blocks are on trend with new deepwater Cretaceous discoveries in the region.”

Blocks 42 and 45 are located approximately 155 miles (250 kilometers) from Paramaribo and cover a combined area of approximately 2.8 million gross acres, at water depths ranging between 650 and 8,500 feet (200-2600 meters).

“We are very pleased to participate in Suriname’s emerging energy sector,” said Ali Moshiri, president of Chevron Africa and Latin America Exploration and Production Company. “These blocks will expand our exploration portfolio in Latin America.”

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