Shell Seeks To Sell Venezuela JV Stake

(Reuters, 12.Oct.2018) — Royal Dutch Shell Plc is negotiating the sale of its stake in a Venezuelan oil joint venture to Paris-based Maurel & Prom , three sources said this week, a move to scale down its crude business in the ailing OPEC-member country to focus on gas. The Anglo-Dutch company is seeking to sell its 40 percent stake in Petroregional del Lago, a joint venture with Venezuela’s state-run oil company PDVSA in the western state of Zulia near Colombia.

The area has been plagued by frequent theft of equipment and near-daily power cuts as Venezuela remains mired in deep recession, hyperinflation and chronic shortages of food and medicine. Foreign companies also have complained in private that joint ventures with PDVSA are stymied by convoluted bureaucracy, dodgy contracts, and lack of resources, according to dozens of sources in the industry.

At Petroregional, Shell has grown frustrated by delays in receiving dividends from PDVSA and a ban on minority partners independently exporting production, one of the sources said. That has deprived Petroregional, which in 2016 produced about 33,000 barrels per day (bpd) of crude, of much-needed income and dented profitability, the source added. In the last few weeks a disagreement with Venezuela has emerged over a fee called an entrance bonus that Maurel & Prom would have to pay to the government, as required by Venezuelan law, to gain access to the field’s reserves, two of the sources said. Negotiations are currently on hold, they added.

***

Energy Analytics Institute (EAI): #LatAmNRG

Maurel & Prom Confirms Discussions With Shell Over Urdaneta West Field In Venezuela

(Maurel & Prom, 12.Oct.2018) — Etablissements Maurel & Prom notes recent press articles and confirms it is working on the acquisition of Shell Exploration and Production Investments B.V.’s 40% interest as “Shareholder B” in Petroregional del Lago Mixed Company, which operates the Urdaneta West field in Lake Maracaibo, Venezuela.

Maurel & Prom Venezuela, subsidiary of Maurel & Prom, has signed a Share Sale and Purchase Agreement (the “SSPA”) with Shell. Under the SSPA terms, the consideration for the acquisition of Shell’s shares in the mixed company is c.€70 million, funded from Maurel & Prom’s existing cash resources.

Petróleos de Venezuela S.A. (PDVSA), wholly owned subsidiaries Corporación Venezolana del Petróleo (CVP) and PDVSA Social (PDVSAS) collectively referred to as “Shareholder A”, jointly own the remaining 60% stake of the mixed company.

The field is currently producing around 16,000 barrels of oil per day on a 100% basis (6,400 barrels of oil per day net to Shareholder B’s 40% interest). The asset offers significant optionality through the development of additional reserves, and the possible extension of the licence duration beyond 2026 (the current licence limit).

The closing of this acquisition remains subject to a number of conditions, amongst others the obtaining of the required governmental approvals, and the finalisation of the negotiations with PDVSA and its subsidiaries (CVP and PDVSAS) on the implementation and the funding of a redevelopment plan to increase the production of the Field, which should be partly funded by operating cash flow, and partly with Maurel & Prom Venezuela’s funds up to an amount of c.€350 million over the period 2018-2023. Maurel & Prom Venezuela’s commitment to provide the project funding is subject to the fulfilment of several conditions, including the progressive reimbursement to Maurel & Prom Venezuela of the portions of project funding attributable to Shareholder A.

Maurel & Prom takes all the necessary steps and actively works on meeting all condition precedents in order to close the acquisition. A further announcement will be made in due course.

***

Energy Analytics Institute (EAI): #LatAmNRG

Aker Solutions Wins Subsea Order for Libra’s Mero Field Offshore Brazil

(Aker Solutions, 5.Oct.2018) — Aker Solutions has signed a contract with Petrobras to provide a subsea production system and related services for the Mero 1 project within the Mero field development, one of the largest oil discoveries in Brazil’s pre-salt area.

The subsea production system will consist of 12 vertical subsea trees designed for Brazil’s pre-salt, four subsea distribution units, three topside master control stations for the Mero 1 Guanabara FPSO and spare parts. The order also includes installation and commissioning support services.

“We’re pleased to become a key supplier to Petrobras and its partners for the first full production project of this major development,” said Luis Araujo, chief executive officer of Aker Solutions. “We have an extensive local workforce and over 40 years’ experience in Brazil and look forward to continuing to play an important role in the development of the country’s pre-salt resources,” he added.

Aker Solutions’ subsea manufacturing facility in São José dos Pinhais and its subsea services base in Rio das Ostras will carry out the work.

The work has already started and deliveries are scheduled for 2020. Installations are scheduled between 2020 and 2023.

The subsea production system will be hooked up to the first full-scale floating production, storage and offloading (FPSO) vessel for Mero, known as the Guanabara FPSO. The FPSO is scheduled to come on stream in 2021 and will have capacity to process up to 180,000 barrels of oil a day and 12 million cubic meters of gas a day.

The ultra-deepwater Mero field is located in the northwestern area of the original Libra block, which is about 180 kilometers south of Rio de Janeiro. First oil was produced in November last year.

Petrobras is the operator of the consortium developing the Libra area. Shell, Total, CNPC and CNOOC Limited are partners. Pre-Sal Petróleo S.A (PPSA) manages the Production Sharing Contract.

The companies are not disclosing the value of the contract. The order will be booked in the third quarter of 2018.

***

Shell Adds Material Acreage To Its Deep-water Position In Brazil

(Shell, 28.Sep2018) — Shell Brasil Petróleo Ltda, a subsidiary of Royal Dutch Shell plc, and its bid consortium member Chevron Brasil Óleo & Gás Ltda, won a 35-year production sharing contract for the Saturno pre-salt block located off the coast of Brazil in the Santos Basin. Shell will pay its share of the total signing bonus for the block, equating to approximately $390 million [R$ 1,562 billion].

“We are pleased to add another material, operated exploration position to our leading portfolio in one of the world’s most prolific deep-water areas,” said Andy Brown, Upstream Director, Royal Dutch Shell. “We continue to grow an exciting and resilient Upstream business of long-term competitive positions in our heartlands while maintaining strong, capital discipline.”

With the addition of the Saturno block (Shell 50% operating, Chevron 50%) won at the Fifth Pre-Salt Bid Round, Shell increases its total net acreage off the coast of Brazil to approximately 2.7 million acres. Shell will engage with Chevron to define specific plans for exploration drilling in the area just won.

Shell is a major oil and gas producer in Brazil with a clear strategy to continue developing an industry-leading portfolio of pre-salt acreage through exploration. The company plans to drill the Alto de Cabo Frio West and South Gato do Mato pre-salt fields in the Santos Basin next year and is proceeding with seismic studies to mature two exploration blocks awarded earlier this year.

Since 2014, Shell has more than doubled its global, deep-water production and expects to exceed 900,000 barrels of oil equivalent by 2020, coming from previously discovered areas in Brazil, the U.S. Gulf of Mexico, Nigeria, and Malaysia. The company is also developing deep-water, exploration plans for its acreage off the coast of Mexico, Mauritania, and in the Western Black Sea.

***

Argentina’s Conventional Oil and Gas Attract Explorers

(Ft.com, Charles Newberry, 23.Sep.2019) — Fresh discovery indicates life beyond Vaca Muerta.

A few years ago, when the giant shale play of Vaca Muerta was starting to lure oil majors such as Chevron, ExxonMobil and Shell to Argentina’s south-west, a small company called Roch struck oil far away at the country’s southern tip.

The result surprised Ricardo Chacra, the company’s president. Roch had found oil in Tierra del Fuego, traditionally a source of natural gas, in a formation that had not been thought to hold much promise after more than a century of exploration in Argentina.

“We found something new,” Mr Chacra says. The find has fuelled optimism that Argentina’s mature conventional oil and gas reservoirs may have more to give. “When you drill into a mature field, you expect to drill into a squeezed lemon,” Mr Chacra says. “You take out what you can. But sometimes you find a virgin lemon.”

Argentina first struck oil early last century on the mainland of southern Patagonia, about 1,000km north of Tierra del Fuego, and exploration and production spread to the west and north-west. Argentina has the fourth-largest proven oil reserves in South America, trailing Venezuela, Brazil and Ecuador and equal with Colombia. But production and reserves sagged under the populist Peronist governments of 2003-15, as price controls and other regulation deterred exploration.

President Mauricio Macri has been removing such constraints to bring capital back to Argentina and his policies have attracted several oil majors. Most of them, however, are going to exploit Vaca Muerta’s shale, the source of unconventional oil and gas that is promising to make Argentina an energy powerhouse for the Americas as a whole.

While a handful of smaller companies has wanted to invest in Vaca Muerta, “it’s incredibly expensive”, says Fiona MacAulay, chief executive of London-based Echo Energy. Instead her company is exploring three conventional blocks in the south of the country at what she estimates to be a 100th of the cost of Vaca Muerta acreage.

Thanks to Argentina’s long history of oil activity, talent, services and infrastructure are available. Gas is delivered by pipeline to Buenos Aires and there are ports to handle oil storage and deliveries.

“The big conventional finds have already been made in Argentina,” says Hugo Giampaoli of local energy consultants GiGa. Even so, they have more to offer. Luciano Fucello, country manager for Houston-based services company NCS Multistage, estimates that only 20 per cent of Argentina’s oil has been recovered.

Daniel Kokogian, a director of Argentina’s Compañía General de Combustibles, says his company has more than doubled its gas output over the past two years in the south, and expects to find “a lot” of conventional oil to recover.

Such potential may not be enough to attract the big guns away from Vaca Muerta but a number of small independents are still taking a shot at a more conventional oil and gas approach.

Canada-based Madalena Energy, for example, is using the cash flow from conventional output to finance drilling in costly Vaca Muerta, says its chief executive, José Penafiel. He estimates that while it takes five to six years to generate a positive cash flow in Vaca Muerta, conventional projects pay back in two to three years.

For companies such as his, which are on far tighter budgets than the majors, he says, “you have to make sure you have the sufficient cash flow to stay in the game long enough to see the value creation of the bigger shale plays”.

An alternative is to push offshore. Several small UK companies, such as London-based Premier Oil and Rockhopper, of Salisbury, Wiltshire, in the south of England, have explored waters around the Falkland Islands that are claimed by Argentina. While still in the pre-development phase, these companies’ finds could spur bids for acreage in Argentine waters in a bidding round, the first in two decades, proposed for this year. “Pretty much every major I know is looking to bid in that offshore round,” Ms MacAulay says.

“Offshore is the last big question mark for exploration in Argentina,” says Mr Kokogian. Much hope is being pinned on waters about 300km-400km from the coast in depths of more than 1,500m. “We have to go to see what is there,” Mr Kokogian adds. “The prize could be big, or very big.”

***

Venezuela Oil Production Continues to Collapse

(Energy Analytics Institute, Jared Yamin, 12.Sep.2018) — The decline is consistent and constant as well as consistently and constantly bad, writes Caracas Capital Market in a research note emailed to clients.

Summary details from the research note follow:

OPEC released the production counts for its member states today and while overall OPEC production was up 278,000 barrels per day (bpd) during the month, Venezuela’s production continued to collapse.

According to OPEC’s August calculations, Venezuela production fell another 36,000 barrels per day (bpd) to 1.235 million bpd. (Venezuela production actually fell 43,000 bpd from the original OPEC July count of 1.278, but OPEC revises their numbers as new data comes in later in the month and moved Venezuela’s July production count down to 1.272 million bpd from the original 1.278 bpd), according to the research note.

“The decline is consistent and constant.”

OPEC calculated that July’s Venezuelan production fall was 42,000 bpd and that June’s fall was 48,000 bpd. In May, Venezuela production fell 43,000; in April, -42,000 bpd; in March, -55,000 bpd; in February -52,000 bpd; in January, -47,000 bpd. Consistently and constantly bad.

In the one year period from August 2017 — when PDVSA was producing 1.918 million bpd — Venezuela has lost 683,000 bpd of production. At the current year average price, that is lost income of $47 million a day and $17.5 billion in a year.

Making this situation worse is that Venezuela’s current 1.235 million bpd production is just a shade more than a third of what the country was producing 20 years ago before Chavez came to power. Hundreds of billions of dollars lost through communism, corruption and incompetence in a country that can ill afford it.

“By the way, we are seeing just one example of how that corruption works in a case playing out before the U.S. Federal District Court in Miami that sucked $1.2 billion from PDVSA in what I label a ‘perpetual money machine for bad guys’ in today’s Miami Herald and El Nuevo Herald, writes Caracas Capital Markets Managing Partner Russ Dallen. “The cast of characters reaches all the way to the top and includes the Derwick boys (especially Francisco Convit), the Boligarch Raul Gorrin (who bought Globovision), the Maduro family (especially the stepsons ‘los chamos’ but also mentions mother Celia Flores and Nicholas Maduro), and a Swiss banker who has copped a deal to tell all (but still had to put up a $5 million bond yesterday).”

Drilling Rigs Fall

Meanwhile, Venezuela’s drilling rig count dropped by one in August, continues the Caracas Capital Market report.

Baker Hughes reports that the number of active drills operating in Venezuela fell to 27 last month, after popping up 2 in July off June’s thirty year low of 26. One of the two drills that was added in July was drilling for gas – the first in over a year. It was still deployed in August.

Having failed to capitalize on its natural gas (much less build the Mariscal Sucre LNG plant) for decades, Venezuela signed a deal last week to link into an already existing gas pipeline at a Shell platform in bordering Trinidad waters and through that pipeline pump gas to Trinidad’s Atlantic LNG plant where it will be converted into LNG for export.

Long time readers will also recall that Rosneft was given a 30 year totally wide-open lease on a gas field in that area last year.

Maduro Goes to China

Finally, as we predicted in our “China Promises Venezuela More Money” Report yesterday and correctly forecast in a Report and Wall Street Journal column in July, Venezuela seems to be making headway in getting help from the Chinese, writes Dallen.

“No one else seems to have been able to accurately uncover and read these Chinese tea leaves, so I am especially proud of our Caracas Capital team. We continue to knock the ball out of the park for our clients,” writes Dallen.

Maduro has just announced that he is going to China to sign some big new deals.

Minister of Oil and PDVSA head Manuel Quevedo is also in Beijing meeting with CNPC and is offering to expand natural gas agreements as well. Yesterday, Venezuela’s oil ministry released a statement touting that the Sinovensa joint venture had increased oil production from 70,000 bpd to 110,000 bpd.

Aside from oil, gas and drilling, we are anticipating some other upcoming ventures in gold mining, coltan and diamond mining, concludes the Caracas Capital Market note.

***

Concerns Raised Over Contract Release Program in Mexico

(S&P Global, 6.Sep.2018) — Mexico gas market observers have expressed concern that a lack of liquidity and supply guarantees will complicate the final phase of Pemex’s natural gas contract release program, which is designed to allow the entry of new gas marketers.

Mexico’s Energy Regulatory Commission (CRE) last week approved the final phase of the release program, known as PCC for the acronym of its Spanish name. The final rules of the regulation have yet to be published in Mexico’s Official Federal Journal (DOF).

The commission joined the second and third phases of the program as one and set its rules in a motion approved August 31.

In January 2017, CRE approved the program, setting the goal for Pemex to release 70% of its gas marketing contracts under a four-year period.

As of March 2018, Pemex has released 30% of its marketing portfolio, 10% more than the goal established in PCC’s first phase, which began in February 2017.

CRE said Friday the final phase would maintain some first phase rules, including full transparency on offers made to users, and a no-penalty clause to end contracts with Pemex.

Other rules to be retained include one requiring Pemex to provide binding offers to users, and another requiring provision of a base formula to allow comparison of offers from Pemex and new marketers.

The energy manager at one of the largest industrial users of gas in northern Mexico told S&P Global Platts that insufficient access to cross-border pipelines is limiting the entry of new marketers.

“At the time of selecting a marketer, the factors most important for users are the economic benefits and supply warranty,” the manager said.

Industrial users’ largest concern is finding a marketer that can offer a real supply alternative beyond Pemex and CFE, the manager said. “We have seen both state companies have a monopoly in most cross-border pipelines,” he added.

EYES OPENED

“The PCC’s first phase opened the eyes to users of the supply alternatives beyond Pemex as well as the mechanics and rules of the new market,” he said.

Before Pemex’s gas supply was taken for granted and users didn’t know how to optimize its gas supply and consumption, the manager said.

“For users, the opportunity in the PCC program is to diversify their supply portfolio beyond Pemex,” he added.

“It is true Pemex is still behind most cross-border pipeline capacity, but the PCC program has empowered users by giving us more information and thus increasing our negotiating power to a certain extent,” he added.

Gonzalo Monroy, managing director of Mexico City-based energy consulting firm GMEC, told Platts he has concerns related to PCC’s last phase.

“For this final phase, due to the lack of reliable private supplies, practically everyone will sign with Pemex or CFE,” Monroy said.

INFRASTRUCTURE ACCESS

The PCC was well drafted, but realistically it has a limited possibility of being applied. It is hard to migrate to a new marketer if it doesn’t have access to reliable infrastructure, Monroy said.

“Contracts have to be sold desegregated in its different components; companies can quit their contract without a penalty; all that is good. But at the end of the day, everything comes down to supply warranty,” Monroy said.

Mexico seeks to have an open access market, but this goal is difficult to achieve due to lack of liquidity and access to cross-border capacity for new marketers, he added.

Market participants have told Platts that the three private companies growing the most in Mexico are Shell, BP and Macquarie.

Monroy said these companies have enough upstream assets in the US to allow them to negotiate with CFE and Pemex for market access in Mexico.

‘However, as a marketer, if you have no bargaining position, no trading chip, you’re hanged,” Monroy said.

***

Carolyn Wants Details on Dragon Gas Deal

(Trinidad and Tobago Newsday, Sean Douglas, 28.Aug.2018) — Four questions have been posed by Congress of the People leader and former energy minister Carolyn Seepersad-Bachan over the Dragon gas deal signed on Saturday between the leaders of TT and Venezuela.

“Whereas the government may not be able to publicly state the agreed price for gas produced from the Dragon field, it ought to provide details on the pricing formula and other emerging issues related to this project,” she said in a statement yesterday.

Saying the field will boost this country’s gas supply for both liquefied natural gas (LNG) and the petrochemical sectors, she said each use of gas is priced separately.

“In the case of LNG, the price at the well-head is determined based on the net back pricing formula, and in the case of the petrochemical sector NGC’s (National Gas Company’s) re-sale prices are linked to international commodity prices.

“If the same approach is not applied to the pricing of the Dragon gas, the NGC is at risk of its sale price being lower than its cost price thus incurring huge losses.”

Secondly, Seepersad-Bachan asked what is TT’s obligation to the special purpose vehicle (SPV), formed with Shell and PDVSA to build a 30 kilometre gas pipeline for US$100 million.

“What is the percentage holding of NGC in this SPV as this will dictate capital investment required for this project? Additionally, at what point does fiscalisation occur?”

Thirdly, she wondered about the deal in light of the current state of affairs in Venezuela. “Has the Government taken into consideration the geopolitical risks, which significantly impact on the viability and reliability of this project?” Would future governments of Venezuela honour this deal to supply gas at the agreed pricing?

If not, the NGC and the citizens of TT would bear the full cost of lost revenue for ALNG and petrochemical companies, Seepersad-Bachan said. “In addition, the literature is replete with examples of expropriation of assets in the Venezuelan energy sector. This places the US$100 million investment at risk should such an event occur. The Government and the NGC must openly indicate to the citizenry how they intend to mitigate these risks.”

She said answers to these questions will show whether this is “a theoretical dream or an implementable reality.” Seepersad-Bachan alleged Energy Minister Franklin Khan had erroneously likened the Dragon project (which fully lies within Venezuelan territory) to the Loran Manatee project which is a cross-border field.

***

Venezuela Gas Price Deal Competitive—Khan

(Trinidad Guardian, 27.Aug.2018) — Government is giving no details on the pricing structure this country will pay for gas from the Dragon Field under the agreement signed with Venezuela on Saturday, but Energy Minister Franklin Khan is assuring that the pricing structure agreed to was competitive and followed “months of negotiation, serious intervention, serious sharing of information and serious sharing of economic models, to come up with an appropriate gas price”.

Speaking during a press conference at the Hyatt Regency in Port-of-Spain, yesterday, Khan said, “It is no cheap gas. It is competitively priced gas and is obviously no secret Dragon deal.”

Khan said Venezuela has the largest oil reserves in the world, larger than Saudi Arabia, Russia and the United States and has the fifth largest gas reserves in the world, which this country can benefit from.

“It’s a win-win situation, especially since we in Trinidad face challenges on the supply side,” he said.

T&T, he said, also has world-class gas infrastructure through which Venezuela can monetise its gas.

“This provides an ideal opportunity for Trinidad and Venezuela. If I can say so, I think it is a marriage made in heaven,” Khan said.

Khan said he took “umbrage” with the way the media reported on the deal signed in Caracas on Saturday by Prime Minister Dr Keith Rowley and Venezuelan President Nicholas Maduro, as he dismissed a report in another daily newspaper that under the deal the T&T Government would be buying the gas at a mere US$1 per MMBTU. Khan said that was simply trying to create mischief by telegraphing to the Venezuelan people that the government was selling “cheap gas to Trinidad and Tobago”. However, he said the price being paid was substantially more.

Both countries, according to Khan, have benefitted, as T&T could import the gas, process it into LNG and for downstream petrochemicals “and still make a profit and it is a price acceptable to the Venezuelans to get a good monetary return for the resources they own.”

Khan said when Rowley was asked by T&T Guardian journalist Curtis Williams about the price, “Dr Rowley said these gas prices are subject to strict confidentiality clauses. However, he took the liberty to say the prices are very competitive and in some cases lower than what we are paying to domestic upstream producers in Trinidad and Tobago”.

He said it was widely known in the energy sector that “the commercial terms of gas sales agreement are subject to the strictest confidentiality clauses”. As he revealed that he could not even answer a question in the Parliament on pricing when asked some time ago, he said because of the confidentiality clause.

“No government past or present, UNC or PNM, has ever made known to the public any negotiated price of gas,” Khan said.

The PM did, however, reveal that under the agreement the volume of gas to be provided will be 150 million cubic standard feet per day with an option to go to 300 million standard cubic feet per day.

On Saturday, Rowley and Maduro signed two documents – a base term sheet for the Dragon Gas deal which set out the commercial term for the gas sales agreement, including volume and price, which was signed by the Venezuelan state oil company PDVSA, Shell as the private investor and the National Gas Company.

Another agreement was signed where both governments committed to the implementation of the project and to see it to finality. Khan said while it was a cross-border relationship with Shell, PDVSA and NGC, “at its most fundamental level it is a government to government arrangement”. He said the gas deal had the effect of securing “a long-term symbiotic relationship with Venezuela”.

He said it was a pricing model and template to allow them to move forward with other fields, including the Loran Manatee, which was the first cross-border project identified between the two countries more than a decade ago.

The Loran-Manatee field contains in excess of 10 trillion cubic feet of gas with 7.3 TCF on the Venezuela side and 2.7 TCF on the Trinidad and Tobago side of the border. Khan said Maduro suggested and PM Rowley agreed “we should develop agreements for the production of Loran Manatee.”

***

Five Things About T&T, Venezuela’s Dragon Gas Deal

(Loop News, 26.Aug.2018) — On August 25, 2018, an historic agreement was made between Prime Minister Dr Keith Rowley and Venezuelan President Nicolás Maduro for access the Venezuela’s Dragon Field.

Source: PDVSA, Venezuela’s Ministry of Petroleum

Here are five things to know about the Dragon field gas deal:

  1. Dragon will produce 150 million cubic feet per day

The Dragon field, part of the Mariscal Sucre offshore gas project, is projected to produce an estimated 150 million cubic feet per day of natural gas from four wells. The Dragon Field contains approximately 2.4 trillion cubic feet of natural gas.

The Mariscal Sucre Dragon and Patao fields, located in water depths between 328-427 feet (100-130 metres), are situated nearly 25 miles north of Venezuela’s Paria peninsula in Sucre state.

It’s expected that production from Venezuela’s four fields which comprise the Mariscal Sucre project – Mejillones, Rio Caribe, Dragon and Patao – will reach 1.2 billion cubic feet per day of natural gas and 28,000 barrels per day of condensates, and will be directed primarily toward export.

  1. Gas to be transported via 30km gas pipeline

The gas will be transported to the Hibiscus platform off the north-west coast of Trinidad, just 18 kilometres from the gas field. Hibiscus is jointly owned by the T&T government and Shell.

The project involves the construction of a 30km gas pipeline – construction of pumping stations, metering systems and related facilities, the laying of gas pipelines, and the installation of safety and control systems.

In March 2017, Shell signed an agreement with NGC and PDVSA to build a 17km pipeline from the Dragon Gas Field to Hibiscus platform.

  1. PM says details ‘confidential’

Details of the deal are ‘confidential’, according to Dr Rowley, but he said the agreed-upon price was ‘competitive’.

  1. Dragon’s gas to be used for T&T products

In the first phase, the gas from the Dragon will boost the country’s gas supply for both the LNG and the petrochemical sectors. T&T plans to expand domestic gas production to 4.14 Bcf/d by the end of 2021.

  1. Dragon project to cost approximately US$100 million

The project will cost an estimated US$100 million, according to media reports. First gas from Dragon is expected in 2020.

***

Venezuela to Send Dragón Gas to Trinidad

(Energy Analytics Institute, Piero Stewart, 25.Aug.2018) — Venezuela will send its Dragón field natural gas to Trinidad for processing.

That’s according to a deal signed today in Caracas between the governments of Trinidad and Tobago and Venezuela, reported Venezuela’s Ministry of Petroleum in a series of tweets. The countries were represented by Prime Minister Dr. Keith Rowley and President Nicolas Maduro, respectively.

The deal calls for construction, operation and maintenance of a 16-inch diameter submarine gas pipeline that will span 15 kilometers from the Dragón field in Venezuela to the Hibiscus field in Trinidad and Tobago.

Companies involved in the pipeline project include: PDVSA, National Gas Company of Trinidad and Tobago (NGC), and Shell Trinidad and Tobago Limited.

Gas from Venezuela will be used in Trinidad and Tobago to feed the twin-island country’s LNG plant and potentially other industries.

However, it’s still unclear what initial production will look like or when the pipeline will be online.

Venezuela’s National Assembly has not approved the gas agreement. However,  under Venezuela’s gas laws, no approval is needed to move forward with negotiations such as those signed today.

***

MEEI Updates on Status of Trinidad Energy Infrastructure

(MEEI, 24.Aug.2018) — The Ministry of Energy and Energy Industries (MEEI) has been monitoring the impacts of the 6.9 magnitude earthquake which occurred on Tuesday 21st August, 2018 at 5:31 p.m. that reportedly caused some property damage across the country.

Reports from the energy sector companies have, so far, indicated that there have been no visible structural damage to offshore and onshore infrastructure, although assessments are currently ongoing.

Some companies, such has Shell, opted to shut-in offshore facilities to conduct such assessments.

In particular, with respect to Trinmar, some offshore installations have been minimally impacted, the most serious being structural damage to the Block Station Bridge on Platform 4 in the Main Soldado Field. A team of Construction Engineering personnel has since examined the damage with the aim of developing measures to rectify the situation. Plans for corrective measures to restore workmen facilities and other general utilities are also being finalized.

At the Petrotrin Refinery, there have been no reported disruptions, save and except impacts to the loading arm for loading vessels with petroleum products. As such, there is expected to be delays in loading vessels for the time being.

There have been reported impacts to office buildings in Port of Spain such as Albion Plaza, Shell House, NPMC Sea Lots, and Atlantic.

NP has assured that there is an adequate and available supply of fuel at its service stations.

The National Gas Company (NGC) has indicated that there was no damage to its facilities and infrastructure. Atlantic LNG’s facilities and infrastructure at Point Fortin were not affected and continue to produce.

Further, there have been no reported damage to any of the following organisations/facilities:

Petrochemical Plants

— Methanol Holdings Trinidad Ltd

— Point Lisas Nitrogen Ltd

— Yara & TRINGEN

— Caribbean Nitrogen Company & N2000

Natural Gas Liquids Facilities

— Phoenix Park Gas Processors Ltd Power Generation

— Trinity Power Ltd

— PowerGen

— Trinidad Generation Unlimited

The Ministry is awaiting responses from other stakeholders. As assessments continue the public will be advised on any further developments accordingly.

***

Trinidad and Venezuela to Sign Gas Agreement

(CMC, 24.Aug.2018) — Prime Minister Dr Keith Rowley will lead a delegation to Venezuela tomorrow to sign an agreement for the development of the across border gas from the Venezuelan Dragon Gas Field, according to an official statement issued here.

The statement from the Office of the Prime Minister noted that the signing of the terms of the agreement will be between the National Gas Company (NGC), the Venezuelan NGC, Shell, and the Venezuelan state-owned oil and natural gas company, Petróleos de Venezuela, SA (Petroleum of Venezuela).

The agreement was originally scheduled to have been signed here on Wednesday, but the statement said the accord will be signed in caracas on Saturday.

“This was requested and acceded to due to the concerns about the earthquake,” the statement said, in reference to the 7.0 earthquake that rocked both Venezuela, Trinidad and Tobago, and other Caribbean countries on Tuesday evening.

The Dragon Field is located within Venezuela’s maritime territory, just off the north-west coast of Trinidad. It is close to the Hibiscus platform, jointly owned by the Trinidad and Tobago government and Shell.

Shell is also the operator of Dragon. The deal will hopefully see Venezuelan gas from Dragon transported to Hibiscus and then to Point Fortin, where Atlantic will turn it into liquefied natural gas.

“That’s the plan we’ve been working on for the last three months,” Rowley told reporters here in April.

Shell is also the helping the government develop and process gas from Loran-Manatee, which is off the south-east coast of Trinidad, and spans the maritime borders of Venezuela and Trinidad and Tobago.

The Loran-Manatee field has an estimated 10.25-trillion cubic feet of gas of which roughly 74 per cent belongs to Venezuela, with 26 per cent belonging to Trinidad and Tobago.

***

Dragon Gas Deal Finalised Tomorrow

(Trinidad and Tobago Newsday, Carla Bridglal, 21.Aug.2018) – After nearly two years of negotiations between this country and Venezuela the deal that will allow TT to process gas from the Dragon gas field is expected to be finalised tomorrow.

A release from the Office of the Prime Minister (OPM) said the agreement on the final terms for the development of the across the border gas from Venezuela’s Dragon gas field will be signed tomorrow by representatives of the National Gas Company, Venezuela’s state oil company, PDVSA, and Shell, the multinational energy giant with the rights to drill the Dragon field.

OPM said A “high-level Venezuelan delegation” will also participate, along with representatives of the TT Government, to witness this “historic event.”

In late June, Stuart Young, then a Minister of State in the Officer of the Prime Minister, said while discussions were almost complete, price was the main sticking point.

In December 2016, Prime Minister Dr Keith Rowley had visited Venezuela, and along with that country’s President, Nicolas Maduro, signed an agreement that put the plan in motion for TT to process Dragon’s gas.

First gas then was estimated by 2020; that timeline is still on track. Young had given reporters a timeline of 18 months to two years to get first gas here—providing the deal is signed soon.

A special purpose vehicle between multinational energy giant Shell and the National Gas Company (NGC) has been created to lay down the infrastructure; Shell’s pipelines, including those in the North Coast Marine Acreage will be used to transport Dragon’s gas to the Hibiscus platform off the north-west coast of Trinidad and only 18 kilometres away from the gas field.

Hibiscus is jointly owned by the TT government and Shell. The first tranche of Dragon’s production will yield about 150 million standard cubic feet of gas per day (mmscfd), or 26,505 barrel of oil equivalent per day (boed). For comparison,

Petrotrin produces 43,000 barrels of oil per day and 130 mmscfd; bpTT’s Juniper well, which came on stream in the latter half of 2017, produces about 590 mmscfd.

The Dragon field is part of the Mariscal Sucre natural gas complex off the Caribbean coast of Venezuela, north west of Trinidad. That Dragon is just one of the fields in a total acreage reserve of 14.7 trillion cubic feet of gas. Dragon alone contains 2.4 tcf.

***

Major Petroleum Cos. Pay T&T $114.7 Bln during 2010-2016

(Energy Analytics Institute, Aaron Simonsky, 20.Aug.2018) – Payments by major oil and gas companies to the government of the twin-island nation of Trinidad and Tobago totaled $114.7 billion during 2010-2016.

That’s according to figures posted by Strategic Energy Advisor Kevin Ramnarine, who is also the Former Energy Minster of Trinidad and Tobago.

Ramnarine provided the data in a post on LinkedIn.

The payment amounts by major companies to the Trinidad and Tobago government by company follow:

1) BP, $37.1 bln

2) NGC, $32.3 bln

3) Petrotrin, $20.3 bln

4) EOG Resources, $10.6 bln

5) Shell, $8.9 bln

6) BHP, $5.5 bln

TOTAL $114.7 bln

Sources: Various @TTEITI Secretariat, Anthony Wilson and Trinidad Express Newspapers

***

Companies to Invest Nearly $900 Mln in Iñiguazu

(Energy Analytics Institute, Jared Yamin, 12.Aug2018) – In Caraparí, in southern Bolivia, a law was enacted that paves the way for the exploration and exploitation of hydrocarbon resources in Iñiguazu.

Passage of the law is expected to attract investments of close to $900 million, reported the daily newspaper La Razón.

The Iñiguazu area has estimated reserve potential of 1.2 trillion cubic feet (Tcf) of natural gas and 43.9 million barrels of oil (MMbbls), according to the daily.

“Starting next week we will conduct engineering studies,” reported the daily, citing Bolivia’s Hydrocarbon Minister Luis Alberto Sánchez. “Infrastructure related construction work is expected to commence next year,” he added.

The project involves drilling 8 producing wells, construction of collection lines, production facilities and a natural gas pipeline that will connect the Iñiguazu wells with the San Alberto Gas Plant. The pipeline is expected to transport initial production of 1.5 million cubic meters per day (MMcm/d) of natural gas by 2021, rising to 7.6 MMcm/d of natural gas at its peak in 2026.

Activities in Iñiguazu will be conducted by YPFB Andina S.A., YPFB Chaco SA, Repsol, Shell and PAE, according to the daily.

***

Shell calls in a BIG RIG

(Trinidad Express, Aleem Khan, 7.Aug.2018) – More hints that major discovery on the horizon.

Offshore Trinidad was one of two sites in the world where oil and gas service provider Rowan Companies plc debuted its ultra-harsh environment jack-up rigs, New York Stock Exchange (NYSE) investors heard last week. The other site was in the North Sea, offshore continental Europe.

Rowan president and chief executive officer (CEO) Tom Burke said: “While overall market conditions for offshore drilling remain challenging, demand for rigs has improved year to date. Since the beginning of the second quarter 2018, Rowan has been awarded contracts for both drillships and jack-up rigs.

Read the full story here.

***

Atlantic Puts Focus on Process Safety

(Trinidad Guardian, 21.Jul.2018) – Atlantic CEO Dr Philip Mshelbila and Rob DiValerio, BP’s Vice President—Group Process Safety Central, have highlighted the central role of employees in the systems that protect natural gas plants from leaks and other failures.

The two headlined the recently concluded 7th annual Process Safety Week, hosted by LNG production company Atlantic for its employees and service providers at its Point Fortin liquefaction facility.

Process Safety is a framework used by LNG facilities and process plant operations to manage the systems that prevent leaks, spills, equipment malfunction, extreme temperatures, corrosion and metal fatigue, which all have the potential to cause hazardous incidents. In the industry, incidents related to these systems are described as Process Safety incidents. At the Process Safety Week launch event, Dr Mshelbila and DiValerio shared some of their personal experiences in managing the tragic outcomes of Process Safety incidents in Nigeria and USA respectively.

“One of the biggest dangers to Process Safety is complacency due to familiarity,” Dr Mshelbila said. “We cannot rely on luck to be our barrier. We have to live Process Safety if we are going to manage it as the way in which we operate. It cannot be something we switch on and off. Our key objective is that we perform at our best and recognise the accountability and responsibility for Process Safety that comes with each of our roles. Every person has to participate—teamwork is the only way to succeed.”

Echoing the Atlantic CEO, keynote speaker Rob DiValerio additionally highlighted the importance of barrier management —the practice of continuously evaluating and enhancing the systems that protect natural gas plants from leaks.

“Incidents should not be seen as an interruption but as an opportunity to learn,” DiValerio said. “The key factor in ensuring Process Safety performance is simply identifying the barriers used to mitigate the routes of Loss of Containment (of hazardous materials) and understanding how robust they are.”

Established in 2012, Atlantic’s Process Safety Week features lectures, presentations and booth displays, all aimed at deepening employee and service provider knowledge of Process Safety at Atlantic and in the wider industry.

This year’s theme was Enhancing Process Safety Performance. Over three days, 27 sessions were held, featuring presenters representing Atlantic, Shell, BP, NGC, Worley Parsons, Massy Wood Group and Lloyd’s Register. Sessions were also held for night shift personnel, as part of Atlantic’s commitment to expose all employees to industry best practices in Process Safety.

***

Guyanese Tanker Workers Undergo Safety Training

(Stabroek News, 18.Jul.2018) – Approximately 35 Guyanese Pritchard-Gordon Tankers (PGT) workers were educated on safety practices as Shell partnered with the company to host a one-day workshop yesterday.

The workshop was hosted at the Pegasus Hotel, where the workers were taken through the rounds by PGT’s Nick Griffith.

“My main focus for this seminar is to improve safety on board of our ships; not that we have a poor safety record but there are always ways of improving safety on board and it has been proven that little incidents, little triggers can show that there’s underperformance and if we have a lot of small and minor incidents then it’s possible that they can result in larger accidents which we definitely want to avoid,” Griffith told Stabroek News.

He stressed that they have not had any serious incidents in a long time but there have been recurrences of minor ones.

According to the company’s website, PGT “specialises in ocean transportation of crude oil and refined petroleum products in environmentally sensitive areas, using purpose built, shallow draft, double hull tankers.”

Griffith said that he hopes that the workers will be even more equipped than they already are to take the necessary safety precautions when they are working and to ensure that they spread the word to the other workers for a more holistic improvement.

He explained that the main topic of yesterday’s seminar was mooring, which he said is a quite dangerous operation.

“You’re using a lot of ropes under pressure and strain and those ropes, if used incorrectly, can break and the rope will snap and it will whiplash and if that rope hits a person’s leg they could lose it. If it hits them around a vital organ they can ultimately die or fall over and bang their head and it has been seen in the past that mooring is a very dangerous operation,” he said.

***

Stock to Watch: ExxonMobil in Guyana

(OilPrice.com, Meredith Taylor, 10.Jul.2018) – American energy dominance is on the rise.

In March 2018, the U.S. beat its all-time record and pumped more than 10.4 million barrels per day (bpd). Energy stocks are way up on strong forecasts of future demand. Mentioned in today’s commentary includes: Exxon-Mobil Corp. (NYSE:XOM), Chevron Corp. (NYSE:CVX), Pioneer Natural Resources (NYSE:PXD), Marathon Oil (NYSE:MRO), PDC Energy, Inc (NASDAQ:PDCE).

A tight market is looming, regardless of OPEC’s plans to pump more: outages are expected in multiple areas, offering up opportunities for American energy producers to swoop in. The last few years have seen the U.S. emerge as an energy powerhouse. And this is just the beginning.

Here is the best stock with (Guyana exposure) to watch in the space:

Exxon-Mobil Corp.

The biggest of the American super-majors is going back to its roots. Exxon-Mobil, an industry giant with a market cap of $351.8 billion, has its hands in upstream, midstream and downstream. It’s truly international, with operations and investments all over the world.

But increasingly, it’s looking to the U.S. to cover its bottom-line. Both NGL and crude production from Exxon’s U.S. properties have increased since 2013. In January, the company announced it would invest $35 billion in the U.S., in response to the generous tax cuts it received.

As other supermajors diversify and turn towards renewables and natural gas, Exxon is determined to remain a crude player-even if that has caused it to lose its market lead over Shell, narrowing the gap between the two firms to a mere $55 billion, according to Bloomberg. And even as it looks to the U.S., particularly the Permian Basin where it holds 6 billion barrels of oil equivalent (BOE), Exxon’s international posture has grown more sturdy-it’s adding to an already-impressive find off the coast of Guyana.

Exxon stock has risen steadily since the doldrums of February 2018, and the news from Guyana (as well as positive news from the OPEC conference in Vienna) should send it even higher. It always pays to bet on the biggest players. And they don’t come any bigger than this.

***

Stuart Young Leads Venezuelan Energy Talks

(LoopTT, 27.Jun.2018) – Minister in the Office of the Prime Minister, Minister in the Ministry of the Attorney General and Legal Affairs and Minister of Communications Stuart Young led a Trinidad and Tobago delegation in Venezuela on Wednesday.

The team comprised of the President of the National Gas Company of Trinidad and Tobago Limited (NGC), Mark Loquan, former PS Selwyn Lashley and other members of NGC to Caracas, Venezuela to continue negotiations with respect to the Venezuelan Dragon across the border gas field.

The Venezuelan delegation was led by Minister Manuel Quevedo, People’s Minister of Petroleum and President of PDVSA, Vice Minister Douglas Sosa and executives of PDVSA and the Venezuelan Ministry of Petroleum.

Executives of Shell were also in attendance led by Derek Hudson, Country Chair of Shell Trinidad’s operations.

The parties spent hours negotiating, bringing the possibility of the cross-border gas deal closer.

There remains a number of areas where further work is required and Minister Young agreed to return to Caracas, Venezuela in two weeks for the two Ministers to attempt to settle the terms of the agreement.

Minister Young extended an invitation for Minister Quevedo to come to Trinidad to visit the LNG and other downstream Petro-chem operations.

All parties involved remain committed to the Dragon Gas Project becoming a reality.

***

Uncertainty Looms Large Over LatAm Oil

(Oilprice.com, Tsvetana Paraskova, 20.Jun.2018) – While oil industry analysts and market participants are watching Venezuela closely for clues about how low its oil production will go, several other countries in Latin America are holding key elections this year, elections that will no doubt shape the countries’ short and medium-term oil policies. These developments could spell trouble for oil supply and oil investment in South America’s biggest crude-producing nations.

A populist leftist candidate pledging to undo energy reforms is widely expected to win Mexico’s presidential election in two weeks. There has been recent turmoil in Brazil’s fuel sector policies ahead of a wide-open presidential race for the October elections. A newly elected president in Colombia is vowing to amend a historic peace deal with the FARC rebels.

All these events add uncertainties to how politics will influence Latin American countries’ oil policies and investment climate for foreign oil companies, Paul Ruiz and Jena Merl write for The Fuse.

In Colombia, a conservative political newcomer, Iván Duque, won the presidential election this past weekend in the traditionally conservative country. The new president, however, has pledged to revise the 2016 deal with the Revolutionary Armed Forces of Colombia (FARC) rebels that put an end to 50 years of armed conflict. Duque wants to re-write the deal that guaranteed the rebels seats in Congress and allowed them to run in elections.

The new president, like the outgoing president Juan Manuel Santos, will have to face another rebel group, the National Liberation Army (ELN)—a Marxist guerrilla group that sabotages oil industry facilities to protest against foreign companies operating in Colombia. In January this year, Colombia suspended talks with ELN after bombings killed police officers. ELN has repeatedly attacked the second-largest oil pipeline in Colombia, Cano Limon-Covenas, causing oil spills and shutdowns.

Mexico is holding a presidential election on July 1, and a few weeks ahead of the vote, all polls point to populist leftist candidate Andrés Manuel López Obrador having a comfortable lead over other candidates. López Obrador pledges to roll back the landmark 2013 energy reform of outgoing president Enrique Peña Nieto, who opened Mexico’s oil sector to private investment for the first time in seven decades. The jury is still out as to whether López Obrador will backtrack entirely on the oil reforms, but uncertainties remain regarding the investment environment in the country—at least for this year.

Brazil is holding elections in October and the race is still wide open.

But in recent weeks, the country came to an economic standstill due to widespread truckers’ strikes over high fuel prices. President Michel Temer announced subsidies on diesel at the end of May, freezing prices for 60 days.

The recent turmoil in the country’s oil industry and renewed anxiety over political meddling in the energy sector add an uncertainty ahead of the election later this year. Pedro Parente, chief executive at state-run oil company Petrobras, resigned on June 1, after the strikes forced the government to cut diesel prices and after oil workers demanded that Brazil end the one-year-old policy to allow fuel prices be dictated by the market and international crude oil benchmarks.

Yet, some of the world’s biggest oil companies—including Exxon, Chevron, Shell, BP, and Equinor—bid aggressively in Brazil’s latest offshore bid round on June 7, snapping up acreage in three blocks in the coveted pre-salt layer.

Nevertheless, uncertainty over how Brazil will handle oil sector policies until and immediately after the October elections has increased.

Brazil is still expected to be one of the largest contributors to non-OPEC oil supply growth in the coming years. According to the International Energy Agency’s (IEA) Oil 2018 outlook from March, oil production growth from the United States, Brazil, Canada, and Norway “can keep the world well supplied, more than meeting global oil demand growth through 2020.”

According to OPEC’s latest Monthly Oil Market Report, non-OPEC oil supply in the second half of this year is expected to increase by 2.0 million bpd year on year, with the United States leading the pack, contributing 1.4 million bpd to growth, followed by Canada and Brazil.

While uncertainties mount in the political shifts and oil policy choices in other Latin American countries, there’s only one uncertainty left for Venezuela—how fast production from the collapsing oil industry will sink to as low as 1 million bpd. Some analysts reckon the plunge to 1 million bpd is imminent.
***

Brazil Raises $830 Mln in Pre-Salt Auction

(Efe, 7.Jun.2018) – Brazil raised 3.15 billion reais (around $830 million) in fixed signing bonuses on Thursday in its fourth auction of oil blocks in a deepwater region of the Atlantic Ocean known as the pre-salt.

The winner of the largest and most coveted block – known as Uirapuru – was a consortium made up of Brazilian state oil company Petrobras (30 percent stake), Irving, Texas-based supermajor Exxon Mobil (28 percent), Norway’s Statoil (28 percent) and Portugal’s Petrogal (14 percent).

It won the block after offering the government a record 75.48 percent share of so-called profit oil, more than three times the minimum required by the National Petroleum Agency (ANP, Brazil’s oil regulator).

Two other consortiums also were awarded licenses for blocks in the pre-salt region, so-named because its massive reserves are located under water, rocks and a layer of salt at depths thousands of meters below the surface of the Atlantic.

One of them is made up of Royal Dutch Shell (40 percent), San Ramon, California-based Chevron (30 percent) and Petrobras (30 percent), while the other is led by Petrobras (45 percent) and also includes BP Energy (30 percent) and Statoil (25 percent).

Although Petrobras initially only was part of that latter consortium, it exercised its right under pre-salt regulations to be an operating partner in the other two consortiums with at least a 30 percent stake.

The ANP received offers that were well above what had been expected for the three most coveted blocks in the auction. The auction of a fourth smaller block, Itaimbezinho, did not attract any bidders and was declared void.

The bid round was among the most successful in recent years, according to ANP director Decio Oddone.

He said that in addition to the proceeds from the fixed signing bonuses the auction also would guarantee some 40 billion reais (some $10.5 billion) in income for the state over the 30-year lifespan of the contracts in the form of profit-sharing arrangements and taxes and royalties.

The consortium led by Shell and Chevron that won the right to develop a pre-salt block known as Tres Marias offered the government 49.95 percent of the profit oil, more than five times the minimum required.

The third block that attracted interest, Dois Irmaos, was awarded to the Petrobras-BP-Statoil consortium, which offered the government a 16.43 percent share of the profit oil, the minimum proportion required.

“It was a very successful auction because it attracted the attention of the world largest oil companies, which made offers that were higher than what we were expecting; it showed how competitive the pre-salt is,” Oddone said.

He said that all told the Brazilian government would have a nearly 90 percent share of liquid revenues from the development of Uirapuru, adding that such a high level was “not even seen in the Middle East.”

The four blocks on offer on Thursday contain roughly 5 billion barrels of oil and natural gas.

Prior to this latest auction Brazil had only awarded licenses to develop six blocks in the pre-salt region, which contains tens of billions of barrels of hydrocarbon reserves.
***

The Insignificance of Venezuela’s 342-Year R/P Ratio

(Energy Analytics Institute, Pietro D. Pitts, 24.May.2018) – Venezuela’s reserves-to-production or R/P ratio was a remarkable 342 times in 2016 based on reserves of 300.9 billion barrels and production of 2.41 million barrels per day (MMb/d), according to BP’s Statistical Review of World Energy.

Today, in a best-case scenario, Venezuela’s R/P ratio could reach 550 times assuming no decline in reserves but a 38% drop in production to 1.5 MMb/d. Stated another way, Venezuela has enough reserves to last for 550 years, up 61% from 2016. In a presumed worst case scenario, if reserves were to declined for numerous reasons by 10% to 271 billion barrels with the same production of 1.5 MMb/d, Venezuela would still have enough reserves to last for 495 years, up 45% from 2016.

When compared to a Reuters’ peer group (comprised of Exxon, BP, Chevron, Total, Eni, Shell, and Equinor, the former Statoil – see chart above) with a combined R/P ratio of 80, Venezuela’s R/P ratio is still a whopping 7x higher than the seven-company peer group.

For what it’s worth, we know reserves are worth nothing in the ground unless they are produced. Maybe it’s correct and better to focus on reserve quality versus quantity but that still doesn’t drive me from my most important point in the case of Venezuela, a country with a lot of potential, but many more wasted opportunities.

Just think what will happen to Venezuela’s R/P ratio as the denominator approaches zero.
***

PDVSA Ex-President Luis Giusti Says Co. Bankrupt

(Energy Analytics Institute, Jared Yamin, 14.May.2018) – Venezuela’s state oil company Petróleos de Venezuela, S.A. (PDVSA) is bankrupt, at least that what its former president Luis Giusti thinks.

“If you look at the signs … they all point to a company that is bankrupt,” said Giusti during a televised interview on the Bayly show on 27 April 2018 with host Jamie Bayly.

Giusti initiated his career at Shell Corporation in Venezuela. He later worked at Maraven, S.A., a PDVSA operating affiliate. In 1994, Giusti was named chairman and CEO of PDVSA, positions he maintained until March of 1999, according to data posted to the website of the Center for Strategy & International Studies (CSIS), an organization where Giusti served as a senior advisor directly after departing PDVSA in 1999.

At the helm of PDVSA, Giusti oversaw major reforms to the Venezuelan petroleum sector including opening the sector to private participation, which attracted foreign direct investments (FDI) between 1995-2004 estimated at around $30 billion.

An engineer by profession, Giusti graduated from the University of Zulia in 1966, and received a M.S. in petroleum engineering from the University of Tulsa in 1971.

What follows are short extracts from the interview:

BAYLY: Why has Venezuela sent so much oil to the U.S. over the years?

GIUSTI: A lot of Venezuela barrels always went to the U.S. for a reason that is clear and precise, and that is due to the decisions made by many refineries along the Gulf Coast to invest in deep conversion capacity and to buy cheaper raw material.

Of the seven refineries in Venezuela only one is operating and the reason is simple and much more than efficiency losses and installation deteriorations. They’re simply not operating because there is no petroleum in Venezuela to process. (See Note 1)

BAYLY: If the US asked you what it could do to assist Venezuela such as to cease imports of Venezuelan crude oil or cease exports of U.S. gasoline to Venezuela, what would you recommend?

GIUSTI: It’s a bit difficult because you need to surmise the crises the citizens are living right now and take into consideration whether such a measure could turn everything around to achieve a change in a reasonable time in Venezuela. I would say that is the main concern.

BAYLY: How much money has been stolen from PDVSA?

GIUSTI: Venezuela and PDVSA are in the situation they are now due to a mismanagement of funds, without even talking about corruption.

After ten years of discretional uses of resources under the mandate of Chavez, we know that much of the funds went to personal accounts. Over a good 10-year period of Chavismo the amount that has been stolen could easily surpass $100 billion.

BAYLY: Is PDVSA bankrupt?

GIUSTI: Since PDVSA is a company of the state, it will never declare in bankruptcy. But, if you look at signs such as: not being able to pay bond returns, the Chinese’s unwillingness to lend more money, declining production levels, and salaries around $5 per month, among others signs, they all point to a company that is bankrupt.

BAYLY: What about the fact that is now run by military personnel?

GIUSTI: Military personnel who could be good or bad in their profession run PDVSA, but they are military personnel that don’t know anything about the petroleum sector.

BAYLY: How does Venezuela exit this disaster?

GIUSTI: It’s a hard question to answer but we are in the presence of a binary decision. There will not be talks about our understandings, or that we will team up. The scenario comes down to the persons in power leaving or there’s no way to resolve this.

Editor’s Note 1: The PDVSA refineries located in Venezuela include: Amuay (645 Mb/d), Cardon (310 Mb/d), Puerto La Cruz (187 Mb/d), El Palito (140 Mb/d), Bajo Grande (16 Mb/d) and San Roque (5 Mb/d), according to PDVSA data.
***

TT’s Energy Landscape

(Trinidad and Tobago’s Newsday, Richardson Dhalai, 10.May.2018) — Trinidad and Tobago has been involved in the petroleum sector for over 100 years and is the largest oil and natural gas producer in the Caribbean.

However, by the early 1990s its hydrocarbon sector moved from being primarily an oil-based economy to a mostly natural gas-based sector with the construction of the LNG trains at Point Fortin.
The energy sector accounts for around 32 per cent of the country’s gross domestic product (GDP).

In Finance Minister Colm Imbert’s October 2, 2017 budget he said, “Despite the challenges posed by the low price environment, the energy sector faces a very positive outlook based on a number of new gas projects which are scheduled to start production over the next two to three years.”

He said a new tax regime would also be introduced to provide incentives for increased exploration and production that should set the stage for increased oil and gas output.

Oil production for the first five months of 2017 had levelled off at 73,500 barrels per day (bpd), the minister had said, as compared with 73,800 bpd for the corresponding period of 2016, although this amount was well below the rate of 100,851 bpd in May 2010.

The 2018 budget was pegged on an oil price of US$52 and a gas price of US$2.75 per mmbtu.

On May 8, Bloomberg was reporting that Brent crude, the main international benchmark, was trading at US$73.44 while WTI crude, TT’s benchmark, was trading at US$68.29. Natural gas was down slightly to US$2.72 mmbtu.

Five months into the 2018 fiscal year, Energy Minister Franklin Khan presented the first public account of the energy sector at the Hyatt Regency, Port of Spain on March 14. His presentation was themed Our Oil, Our Gas, Our Future.

He said TT continued to be an important oil and gas producing hub and cited the major multinational energy giants which continued to maintain a presence in the country, such as bpTT, Shell, BHP, EOG Resources and Perenco.

He said the upstream companies had committed to spend over US$10 billion in exploration and development activities over the next five years, with the effects already being felt as of December 2017. Natural gas production, which had fallen to 3.2 bcf/d per day had reached a daily production of 3.8 bcf/d.

The US$10 billion is expected to be spent on capital goods such as rigs, sub-sea equipment, seismic equipment, platforms, turbines and pipes with the exception of platforms.

The investments include the BP Angelin project, which is due to come on-stream in 2019 and is expected to provide in excess of 550 mmscf/d.

The other projects include De Novo energy exploration of Block 1 (a) off Trinidad’s west coast; the East Coast and North East Coast development projects of Shell, such are Starfish, Dolphin, Dolphin Deep, Endeavour and Bounty fields, and the Cassra and Orchid on the North East Coast.

BHP has also announced a deep-water natural gas discovery in Block 5 on the East Coast, with preliminary assessments indicating between five to ten tcf of gas with a high probability of oil.
Approximately nine exploration wells are expected to be drilled, including three deep-water wells.

Khan said TT’s gas reserves, based on the last Scott Reserves audit, were 22.7 tcf and gas resources were estimated at 43.7 tcf.

He said the audit information did not include the gas finds of the BHP discovery in Block 5 or the BP Savannah and Macadamia fields of 2 tcf.

“Our gas reserves are consumed at the rate currently estimated at 3.5bcf/d or 1.2 to 1.4 tcf per annum,” he said, adding this was divided between LNG production (60 per cent) and the downstream industries including power generation, which consumed 40 per cent of the gas supply.

Currently 99.8 per cent of power generation is fuelled by natural gas and 0.2 per cent by diesel.

He said data from the Ministry of Energy and Energy Industries and the Ministry of Finance reveal that taxes and royalties collected from the sector have been on a downward trend.

He said energy sector revenue, which peaked at $28 billion in 2008, fell to $1 billion in 2017 and cited falling energy prices as playing a part for the reduced revenue.

According to the Ministry of Energy, TT’s 2017 crude oil production stood at 71,824 bpd while its refinery output at Pointe-a-Pierre is 135,000 bpd.

The country’s proven oil reserves is 199.54 million barrels, while probable reserves are 85.46 million barrels and possible reserves are 124.77 million barrels.

Natural gas production is currently 3.4 bcf/d with proven reserves standing at 43.45 million barrels; probable reserves at 24.39 million barrels and possible reserves at 30.83 million barrels.

Meanwhile, State-owned oil company Petrotrin has identified the South West Soldado Field Development as one of the most immediate opportunities for increasing indigenous crude oil production.

The project, which is divided into three phases, is currently in its first phase of execution, which includes the installation of a temporary compression and production facility, drilling of eight new wells and the reactivation and workover of inactive wells.

The first phase also includes the installation of a new gas sales pipeline; installation of additional infrastructure and submarine pipelines to accommodate the increased production of fluids (inclusive of gas lifting capability for the reactivated wells) and the installation of replacement main oil bulk line from RP10 to RP1.
***

Shell Made Mistake Pulling Out of Guyana basin

(CaribbeanLife, Bert Wilkinson, 31.Jan.2018) — Now that Guyana’s oil and gas basin has been deemed as one of the hottest and most exciting prospects in the world, Shell Oil has to be regretting its decision to withdraw as an investment partner with United States giant ExxonMobil, which has so far drilled six successful wells offshore Guyana worth about 3.2 billion barrels of oil, officials said Monday, Jan. 29.

Minister of Natural Resources Raphael Trotman said Exxon’s mid 2015 “world class” oil and gas find has clearly taken away all the fears and apprehensions about wasting investor dollars exploring offshore Guyana and Shell is one company which has missed out on the chance to cash in on one of the world’s largest oil finds in more than a decade. Exxon plans to begin producing about 120,000 barrels of oil daily in early 2020. This will make Guyana the largest producer in the Caribbean Community. The others are Trinidad, Suriname and Barbados.

“Shell was with Exxon on the Stabroek block and pulled out. They now maybe rue the day that they ever did that. Now, Shell has signaled that it wants to come back to Guyana,” Trotman noted, saying that all the major oil and gas companies in the world are either vying for their own offshore blocs or buying into smaller companies which have deep water concessions near Exxon’s highly successful offshore fields.

Exxon spokeswoman Kimberly Brasington Monday confirmed that Shell was the original partner with Exxon in the six million acre-plus concession area after Exxon had signed its exploration agreement with Guyana back in 1999 “but chose to pull out. They made the decision not to take the risk. We therefore had to go out there and look for new partners in Hess Oil and Nexen (of China). Yes that was indeed the case,” she said.

Geology and Mines Commissioner Newell Dennison said Shell pulled out about a decade ago and has been sending signals about coming back into the basin but he has seen no paper work regarding this so far.

Exxon and its partners plan to drill 17 wells in the first phase of their offshore venture and up to 40 others ion phase two. The company has already filed paperwork for permission to begin preparations for phase two of its offshore operations and has begun public consultations about this phase.

Spain’s Repsol, Tullow Oil of the United Kingdom, Chevron, Brazil’s Petrobras, Eni of Italy, TOTAL of France and British Petroleum are among big oil players all vying for participation in the country’s fledgling oil and gas sector.

“These companies are only expressing interest because ExxonMobil has de-risked the basin. Zero from zero is nothing. If you have oil and no one is troubling it, then it is worth zero. The oil may be worth a lot, but only if it is produced. We are moving to production, but it took ExxonMobil to find what others have been looking for,” Trotman said.

***

Trinidad – Upstream Activity Snapshot in 2018

(Kevin Ramnarine, Strategic Energy Adviser). Former Minister of Energy. Business School Lecturer. International Speaker, 3.Jan.2018) – This is a summary of upstream activity for Trinidad and Tobago in 2018.

1) Rowan will have 4 rigs drilling in 2018. By June 2018 all four will be working simultaneously. Two of these will be with BP, one with EOG and one with Shell. Good luck Rowan.

2) BHP Billiton resumes exploration drilling in Deepwater using the Transocean Invictus. This drilling is related to Production Sharing Contracts signed between 2013 and 2014. A lot of fingers are crossed.

3) Shell does the Starfish Infill Drilling (SID) project, which sees Shell try to tap the reserves of Starfish. They are using a Mearesk Semi Submersible for this. Good luck Shell.

4) DeNovo will have first gas from the Iguana field by Q2 2018. This will make DeNovo, Trinidad’s fifth natural gas supplier. Positive news indeed.

5) BP will be drilling wells for the Angelin project for which first gas is Q1 2019. Sadly we lost the platform in 2017 but the project is on schedule. Angelin became more prospective after the 3D seismic Ocean Botton Cable (OBC) survey of 2012 to 2013.

6) The economy will benefit from a full year of BP Juniper production and this will cause positive economic growth for the first time in 3 years. Congrats to all involved in this very historic project.

7) Work will start on the fabrication of the BP Cassia C compression platform. Hopefully some of this will be done at La Brea.

8) BP will be doing infill drilling on Cannonball and Cashima in 2018.

9) Lease Operators Limited (LOL) will be drilling exploration wells in their Rio Claro Land Block. That block was awarded in 2014. We expect at least 2 exploration wells in 2018 in this block. Maybe we will have an oil discovery on land for the first time since Carapal Ridge (many years ago).

Editor’s Note: Kevin Ramnarine is a strategic energy adviser and the former Trinidad and Tobago Minister of Energy. He is also a business school lecturer and international speaker.

***

PDVSA, Shell Discuss Gas Exports

(Energy Analytics Institute, Piero Stewart, 21.May.2017) – PDVSA and Shell continue to conduct discussions related to the exportation of Venezuelan natural gas to the twin-nation island of Trinidad and Tobago, reported PDVSA in an official statement.

“We are evaluating the base of resources for export,” announced PDVSA, citing PDVSA Gas President César Triana. “We have received proposals to finalize the accelerated production project and future development of the field to boost export volumes to the Caribbean nation,” she said. Discussions between the companies were headed by PDVSA President Eulogio Del Pino and PDVSA Gas President Cesar Triana and Shell Venezuela and Trinidad President Luis Prado.

Discussions between the companies teams focused on three aspects: gas volumes, gas prices and the field interconnection point. An earlier agreement signed by the companies entails construction, operation, and maintenance of a gas pipeline to transport the fuel source between both nations and span from the Dragon field located in Sucre state to the Hibiscus field in Trinidad. The project is estimated to have achieved the 91% completion mark, PDVSA reported.

Paria North — where the gas will come from — contains 14.3 trillion cubic feet (Tcf) of gas reserves in four fields: Dragón, Patao, Mejillones and Río Caribe. The Dragón field alone contains 3.1 Tcf, according to PDVSA.

Discussions also focused on the flaring of gas in North Monagas and future recollection of this gas and other general themes related to the Petroregional del Lago mixed company. The initial volumes from the Dragón field will be destined for the Venezuelan domestic market to substitute the use of diesel at thermo-electric plants, and is estimated to free up 32,000 barrels per day of fuel.

***

Petrobras, Total Finalize Strategic Alliance

(Petrobras, 1.Mar.2017) – Petrobras and Total signed the sales contracts for the assets in the Strategic Alliance, as set out in the Master Agreement signed on the 21st of December, 2016.

The contracts signed yesterday form a Strategic Alliance between both companies creating new partnerships in the Upstream and Downstream segments, and they reinforce technical cooperation in operations, research and technology. This alliance should allow both companies to bring together their internationally recognized expertise in all segments of the oil and gas value chain in Brazil and abroad.

Through these contracts:

– Petrobras will transfer 22.5% of the rights to Total in the concession area called Iara (comprising Sururu, Berbigão and Oeste de Atapu fields, which are subject to unitization agreements with the area called Entorno de Iara, a transfer of rights area in which Petrobras holds a 100% stake), in the Block BM-S-11. Petrobras will continue as operator and hold the largest stake, with 42.5%. The partnership with Total will allow Petrobras to reduce its investment and will benefit from technological solutions for its development that will be jointly studied by Petrobras and Total, maximizing profitability and the volume of oil to be recovered. BG E&P Brasil, a subsidiary of Royal Dutch Shell plc, with 25%, and Petrogal Brasil, with 10%, are also part of the consortium.

– Petrobras will transfer 35% of the rights to Total, along with its operation, in the Lapa field concession area, in Block BM-S-9. Petrobras will keep 10%. The Lapa field is in the production phase and came onstream in December 2016. Total, as the new operator of this field, will benefit the Consortium by incorporating valuable experience in deepwater projects for the next phases of the challenging Lapa project, which has distinct characteristics from other operating pre-salt fields. BG E&P Brasil, a subsidiary of Royal Dutch Shell plc, with 30%, and Repsol-Sinopec Brasil, with 25%, are also part of this consortium.

– Sale of Petrobras’ 50% stake to Total in Termobahia, which includes two cogeneration plants, Rômulo de Almeida and Celso Furtado, located in Bahia. Both plants are connected to the regasification terminal located in São Francisco do Conde, Bahia, where Total will take the regasification capacity to supply gas to the thermoelectric plants. This initiative constitutes an innovative partnership in the Brazilian thermal market.

The above contracts are in addition to other agreements already entered into on the 21st of December, namely: (i) Letter granting Petrobras the option to purchase a 20% stake in block 2 of the Perdido Foldbelt area, in the Mexican sector of the Gulf of Mexico, only taking on future obligations in proportion to its stake (ii) Letter of intent for joint exploration studies in the exploratory areas of the Equatorial Margin and the Santos Basin; and (iii) Technological partnership agreement in digital petrophysics, geological processing and subsea production systems.

The deal includes Total paying $2,225 million to Petrobras, made up of $1,675 million in cash for assets and services, a $400 million line of credit that could be triggered by Petrobras for part of their investment in the Iara development fields and $150 million for contingent payments.

After signing the contracts, Pedro Parente, CEO of Petrobras and Patrick Pouyanné, Chairman and CEO of Total, have declared: “We are delighted today to see our Strategic Alliance becoming reality. These new partnerships together with a reinforced technological cooperation should create significant synergies and values, mutualizing our operational excellence and further reducing costs on our joint projects for the benefit of both companies”

The deal is subject to the approval of the relevant regulatory entities, the potential exercise of preemptive rights by current Iara partners in addition to other preceding conditions.

For Petrobras, this Strategic Alliance is an important part of the Petrobras 2017-2021 Business and Management Plan. It increases information, experience, and technology sharing, which strengthens corporate governance, and improves the company’s financeability through mitigation of risks, cash inflows, and the release of investments.

For Total, these new partnerships with Petrobras reinforce Total’s position in Brazil through the access to new fields in the Santos Basin while entering a promising gas value chain.

Total and Petrobras

Currently, Petrobras and Total jointly participate in 19 Exploration and Production consortiums worldwide. In Brazil, the companies are partners in the development of the giant Libra field, which is the first Production Sharing Contract in the Brazilian pre-salt Santos basin. Outside Brazil, Petrobras and Total are partners in the Chinook field in the US Gulf of Mexico, in the deep-water Akpo field in Nigeria and in the gas fields of San Alberto and San Antonio/Itau in Bolivia, as well as in the Bolivia-Brazil gas pipeline.

***

Petrobras, Total Move Forward with Alliance

(Petrobras, 21.Dec.2016) – Petrobras signed a Master Agreement with the French company Total, in connection with the Strategic Alliance established in the Memorandum of Understanding signed on 10/24/2016, as previously announced to the market.

Entering into strategic partnerships is an important part of Petrobras’ 2017-2021 Business and Management Plan, as it contributes to mitigating risks, strengthening corporate governance and sharing information, experiences and technologies, in addition to improving the Company’s financial viability through cash inflows and the release of investments.

Petrobras and Total have strong similarities in the upstream segment, sharing a relevant common base of E&P assets and the search for technological development in similar themes.

The companies jointly participate in 19 consortiums worldwide in exploration and production in key projects such as the Libra area, which is the first production sharing contract in the Brazilian pre-salt in Santos Basin, besides exploration areas in Equatorial Margin, Espírito Santo Basin and Pelotas Basin. In addition, both companies are partners in the Brazil-Bolívia gas pipeline.

With this new agreement, both companies will strongly reinforce their technological cooperation in the areas of geoscience, subsea systems and joint studies in areas of mutual interest, aiming to reduce investment risks and increase the probability of exploratory success over the next years. The companies will also become partners in the Iara and Lapa fields, in the pre-salt Santos Basin, and in two thermal plants, sharing the use of the regasification terminal infrastructure in the state of Bahia.

The companies also undertake to expand their joint activities outside Brazil, with Petrobras having the option of taking a stake in the Perdido Foldbelt area in the Mexican portion of the Gulf of Mexico.

The transaction has a global estimated value of $2.2 billion including cash, contingent payments and the carry of investments in production development of common assets to both companies, to be paid by Total to Petrobras and its subsidiaries as appropriate.

The signing of the relevant Sale and Purchase Agreements (SPA) related to the assets from this Master Agreement is subject to internal and external control and regulatory approvals, including the Brazilian Federal Accounting Court (TCU), potential preemptive rights from the current partners of Iara, plus other precedent conditions. The companies have a mutual commitment to make all the necessary efforts to sign all contracts within 60 days.

The main terms and conditions of this Agreement are as follows:

– the sale of a 22.5% interest to Total, in the Iara area (Sururu, Berbigão and Oeste de Atapu fields) in Block BM-S-11. Petrobras will remain the operator and will keep the largest stake in that consortium, with a 42.5% interest.

– the sale of 35% interest to Total in Lapa field in Block BM-S-9, with transfer of the operation to Total. Petrobras will have a 10% interest in this concession.

– Petrobras’ option to take a 20% participation in block 2 of the Perdido Foldbelt area in the Mexican portion of the Gulf of Mexico, acquired by Total in partnership with Exxon in the round of bidding held by the Mexican government on 12/05/2016.

– shared use of the Bahia regasification terminal, with a capacity of 14 million m3/day.

– partnership, with Total holding a 50% stake, in the thermal plants Rômulo de Almeida and Celso Furtado, located in Bahia, with energy generation capacity of 322 MW.

– joint studies in the exploratory areas in the Equatorial Margin and in the southern area of Santos Basin, taking advantage of the existing synergy between the two companies, since each has outstanding geological knowledge of the oil basins located on both sides of the Atlantic.

– technological partnership agreement in geological processing and subsea engineering, in which the companies have complementary knowledge, which can boost the gains from the application of new technologies in the partnership areas.

The information below refers to the concessions established in the Agreement:

Concessions in Upstream

In the Iara concession, Petrobras holds a 65% interest and is the operator. Shell, with 25%, and Galp with 10%, are partners in this area, which is part of Block BMS-11. The reservoirs of this concession have higher complexity and are in the production development phase. The partnership with Total in this area will bring benefits such as the release of investments and new technological solutions for its development, maximizing profitability and the volume of oil to be recovered.

The limits of this consortium extend into the Entorno de Iara area, from the Transfer of Rights agreement, in which Petrobras holds a 100% interest. The fields Berbigão, Sururu and Oeste de Atapu must enter into Individualization Production Agreements (unitization) with this area of the Transfer of Rights.

In the Lapa field, Petrobras holds a 45% interest and is the operator. Shell, with 30%, and Repsol with 25%, are partners in this field, which is part of BM-S-9 block. The development of the Lapa field is at an advanced stage, with the recent start of production, as announced on 12/20/2016, and presents geological characteristics and oil quality different from other pre-salt fields. Total, as future operator of this field, will bring benefits to the consortium, by incorporating its experience and knowledge in the continuity of its development plan.

The technological partnerships in the Iara and Lapa areas will develop and apply certain subsea technologies in a pioneering manner in Brazil. The efforts to reduce risks and increase the probability and the success in exploration will rely on a 4D seismic application in the context of carbonate reservoirs, with specific studies on CO2 migration and geomechanical studies, in addition to the development of a methodology for the construction of models to support investment decisions.

Gas & Energy Concessions

In the case of the G&E area, Petrobras and Total are forming an innovative partnership in the Brazilian thermal market. The initiative is aligned with the strategies of Petrobras for the Gas and Energy segment in the 2017-2021 Business and Management Plan, which establishes the restructuring of the Energy Businesses and maximizes the value generated in the gas chain. This vision considers a regulatory evolution, that is already under discussion with Brazilian federal authorities, forecasting an improvement of the procurement rules, access to the pipeline network and LNG regasification terminals.

The partnership with Total includes two thermal plants (Rômulo Almeida and Celso Furtado), connected to the Regasification Terminal located in São Francisco do Conde, in Bahia.

***

New Libra Well Confirms Extension of Petrobras Oil Find

(Petrobras, 15.Jun.2016) – The Libra Consortium has concluded the drilling and evaluation of the seventh well in the block, located in the pre-salt of the Santos Basin. The well found the thickest oil net pay column ever encountered in Libra, reaching 410 meters. This column overcomes the last found (301 meters), announced in March this year.

The new well, located in the northwest portion of the block and 180 kilometers off the Rio de Janeiro state coast, confirmed the discovery of good quality oil (27-degree API) in reservoirs with excellent productivity.

The well, named 3-BRSA-1339A-RJS (3-RJS-742A) and informally known as NW2, is located 10.3 kilometers south of the discovery well 2-ANP-2A-RJS. This drilling is part of the Discovery Evaluation Plan of the 2-ANP-2A-RJS, approved by the National Oil, Natural Gas and Biofuels Agency (ANP), on February 26, 2016.

To date, seven wells have been drilled in Libra (six by the Consortium) and the eighth well (3RJS-743-A), also in the northwest area of the block, is being drilled. The area of Libra was the first award under the production sharing regime.

The Libra Consortium is composed of Petrobras (operator, with 40 percent WI), Shell (20 percent WI), Total (20%), CNPC (10 percent WI) and CNOOC (10 percent WI), and the Production Sharing Contract manager is Pré-Sal Petróleo S.A. (PPSA).

***

Ecopetrol Announces Caribbean Deepwater Find

(Ecopetrol S.A., 28.Jul.2015) – Ecopetrol informs that at a depth of 3720 meters, the Kronos-1 well verified the presence of hydrocarbons in ultra-deepwater of Colombian south Caribbean area. This discovery proves the geological model proposed for an unexplored area with high hydrocarbon potential.

Kronos-1 is located in block Fuerte Sur, 53 kilometers (33 miles) offshore, where partners Anadarko, operator, and Ecopetrol, each hold 50% interest.

“This discovery adds to the one accomplished in December at the Orca-1 well, located in the deep water of Tayrona block offshore Guajira, where we are partners with Petrobras, Repsol and Statoil,” reported Ecopetrol, citing company president Juan Carlos Echeverry. “These results are very important and confirm the potential of the Colombian Caribbean petroleum system in a vast area and are aligned with Ecopetrol´s new strategy, in which one of the key areas is the exploration on high potential marine basins.”

According to operator’s quarterly operations report, after drilling at a water depth of 1,584 meters (5,195 ft), the well reached total depth of 3,720 meters (12,200 ft) and encountered a net pay thickness between 40 to 70 meters (130-230 ft) of gas bearing sandstones.

Ecopetrol and Anadarko’s integrated technical teams are continuing to evaluate the Kronos discovery results. Nowadays the drilling operation continues, aiming to reach a deeper target to determine possible additional results.

In 2012, the Ecopetrol – Anadarko partnership undertook exploration in the South Caribbean in blocks Fuerte Norte , Fuerte Sur , COL5, URA4 and Purple Angel.

Our partner, Anadarko, is one of the most recognized companies worldwide for its experience in deepwater and ultra-deepwater exploration, project management and execution. Currently Anadarko is executing the biggest seismic acquisition campaign in the history of the Colombian Caribbean with an extension of more than 16,000 square kilometers.

Once activities at Kronos-1 are concluded, the drillship Bolette Dolphin, employed in this operation, will move to Fuerte Norte Block to continue drilling Calasu-1 well, located 145 kilometers or approximately 100 miles north east of Kronos-1.

***

Petrobras Libra Consortium 2nd Extension Well

(Petrobras, 24.Mar.2015) – The Libra consortium has finished drilling extension well 3-BRSA-1267-RJS/3-BRSA-1267A-RJS (3-RJS-735/735A). The drilling results confirmed the presence of a hydrocarbon column approximately 200 meters deep in reservoirs with good permeability and porosity characteristics.

Informally known as C1, the well is located in the central part of the Libra block, in Santos Basin, around 220 km offshore from the city of Rio de Janeiro.

The final depth reached was 5,780 m, including a water depth of 2,160 m. This is the second well successfully drilled by the Libra consortium, and is 18 km from the first well, called 3-RJS-731.

The hydrocarbon and CO2 bearing intervals were calculated through electrical profiles and fluid samples, which are being characterized through laboratory analysis.

The consortium will continue with the exploration plan by drilling new wells in order to evaluate the Libra area, which covers around 1,550 km2.

The Libra consortium is composed of Petrobras (Operator, 40% WI), Shell (20% WI), Total (20% WI), CNPC (10% WI) and CNOOC (10% WI), as well as Brazilian state-owned company Pré-Sal Petróleo S.A. (PPSA), which is the contract manager.

***