BP, Pan American Eye Exporting Argentina Shale Gas As LNG Via Chile

(S&P Global Platts, 15.Nov.2018) — Pan American Energy, the second-biggest oil producer and third for gas in Argentina, is working with BP on potentially exporting LNG out of Chile, a project that could prove faster to get Vaca Muerta shale gas to market than building a liquefaction facility in Argentina.

The project is in the conceptual design phase and would involve delivering supplies over an existing Argentina-Chile pipeline to the Quintero LNG regasification terminal in Chile, said Alejandro Lopez Angriman, vice president of reserves development at Pan American.

The Quintero terminal “can be turned around so it can liquefy to export,” he said on the sidelines of an energy conference in Mendoza, Argentina.

The pipeline has 10 million cu m/d of capacity for moving supplies from Vaca Muerta to Chile, but is mostly running empty. It has been used over the past few June-to-August winters to bring regasified LNG to Argentina from Chile.

To deliver supplies to Chile, the pipeline would have to be modified with a loop, Lopez Angriman said.

BP — which owns 50% of Pan American alongside Bridas, itself 50% owned by China’s CNOOC — is helping on the conceptual engineering for the project, he added.

The project could cost around $300 million if it goes forward, he added, with the first train exporting 25 million cu m/d.

LOOKING FOR NEW MARKETS

The research into the project comes as gas production surges in Argentina, led by Vaca Muerta, one of the world’s largest shale plays.

The country’s overall gas production rose 14% to 130 million cu m/d this year from a 16-year low of 113.7 million cu m/d in 2014, allowing the country to restart exports by pipeline to Chile after an 11-year suspension.

The Energy Secretariat estimates that with enough investment Vaca Muerta could double the country’s gas production over the next five years to 238 million cu m/d, allowing exports to surge to 100 million cu m/d in 2023 from less than 1 million cu m/d this year.

In the late 1990s and early 2000s, Argentina exported 20 million cu m/d to Brazil, Chile and Uruguay, and the pipelines are still in place. The country halted exports in the mid-2000s as production plunged, bringing shortages and a surge in imports of Bolivian gas and LNG. Imports have averaged 30 million cu m/d since 2012, but started declining this year, according to Energy Secretariat data.

Pan American got a permit this year to export gas to Chile, and it likely will start to make deliveries during the upcoming December to February summer for consumption in that market, Lopez Angriman said.

But he said that won’t be enough to sustain a larger development of Vaca Muerta, where he estimates one field could easily supply the LNG export terminal.

“The field could produce 25, 50, or even 100 million cu m/d,” Lopez Angriman said. “It’s incredible the number of wells that you can do in Vaca Muerta for gas.”

Frackers, he added, have de-risked the gas potential in Vaca Muerta, and the next step is to find the capital to put it into full-scale production. But to attract investors, more pipelines are needed to get the gas out and additional markets must be found to increase sales so production can be sustained year-round, not slowed during the summer with the closing of wells. State-run YPF, the country’s biggest gas producer, had to close gas wells in the third quarter of this year, in part because warming temperatures and a contracting economy reduced demand.

Argentina has sharp fluctuations in gas demand, from 115 million cu m/d in the summer and peaks at 180 million cu m/d in the winter, according to data from Enargas, the national gas regulator.

“It is not a good thing to convince investors to invest in shale gas when production has to be halted during the summer,” Lopez Angriman said.

CUTTING WELLHEAD COSTS

While gas exports can be increased to neighboring countries, these markets suffer the same predicament as Argentina: their demand for gas plunges in the summer. That means LNG must be pursued if output from Vaca Muerta is to be expanded, he said.

But to do that, a big challenge is to bring down development costs in the play so the gas can be competitive against Australia, Qatar, the US and other suppliers in sales to Southeast Asia, where demand is expected to grow, Lopez Angriman said.

He estimates that at around $3/MMBtu, sales can be competitive. But to get there, Vaca Muerta development costs must come down 30%, and the focus is on easing the strain of frack sand, which accounts for 30% of the well completion cost, he said.

Frackers have shaved the cost of sand to $190/mt from $250/mt over the past few years, but it is still higher than the $60/mt figure in the US.

“If we are going to compete with the US or Canada, one way or another we have to reduce the cost of sand,” he said.

Help is to come from moving more sand by boat and train to Vaca Muerta, located in the southwest. Most of the sand is currently being trucked 1,000 km (621 miles) from Entre Rios, a central province, with transport accounting for 50% of the total cost of sand.

There is a government-led plan to extend a cargo railway to Vaca Muerta, but it is not likely to start for three to four years. Once it is in operation, the cost will come down because it is cheaper to move the sand from Entre Rios by river and ocean to Bahia Blanca, an Atlantic port where it can be loaded onto the train for delivery to the well sites.

THE ARGENTINA LNG OPTION

Pan American also is looking at the option of building liquefaction capacity in Argentina, as are other companies.

On Monday, YPF said it plans to install a floating liquefaction barge in Bahia Blanca to export up to 2.5 million cu m/d of LNG from 2019, and then work on building a larger export terminal.

The government, meanwhile, is studying a project for exporting LNG from a six-train onshore terminal in Bahia Blanca, likely starting in 2023 with shipments of 40 million cu m/d, increasing to 120 million cu m/d in 2025.

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#LatAmNRG

BP Extends Contract With Joe Douglas In Trinidad By One Well

(Energy Analytics Institute, Jared Yamin, 2.Nov.2018) — BP has extended its contract with the Joe Douglas in Trinidad by one well with an expected duration of 76 days. The extension includes one additional two-well option at then market rates, Rowan Companies plc announced in an official statement.

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#LatAmNRG

Air BP Nationalization In Bolivia “Technically” Not Finalized

(Energy Analytics Institute, Jared Yamin, 14.Oct.2018) — Bolivia’s Hydrocarbon Minister Luis Alberto Sánchez, acknowledged that nationalization of Air BP, a subsidiary of British Petroleum, in charge of marketing jet fuel and airplane gasoline, wasn’t completed due to lawsuit filed by Aerosur.

“We haven’t finalized the transfer of shares in Air BP to YPFB due to a contingency problem resulting from a lawsuit brought about by Aerosur relating to Air BP,” reported the daily El Diario, citing Sánchez. “As long as it’s not resolved, we can’t move forward,” he said.

On May 1, 2009, Bolivia’s President Evo Morales announced nationalization of Air BP through Supreme Decree 111, and ordered the Bolivian Armed Forces to intervene in the company.

Although the shares of Air BP haven’t officially been transferred to the Bolivian state, Sanchez assured the nationalization decree related to the company had been fulfilled.

“YPFB has control of the company,” he affirmed.

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Energy Analytics Institute (EAI): #LatAmNRG

Petrobras to Boost Oil Output in 2019, Cut Debt $10 Billion – CFO

(Reuters, Devika Krishna Kumar, Simon Webb, 17.Sep.2018) — Brazil’s state-run oil giant Petróleo Brasileiro SA aims to raise output as much as 10 percent to around 2.3 million barrels per day (bpd) in 2019 and cut net debt by $10 billion (7.62 billion pounds), Chief Financial Officer Rafael Grisolia told Reuters.

The world’s most indebted oil company is on course to reduce debt to $69 billion by the end of this year despite falling short of its $21 billion asset sales target, Grisolia told Reuters in an interview in New York late Friday.

The firm has significantly reduced its net debt from the $106 billion it had accumulated in 2014 to finance development of massive deepwater Atlantic oil fields. Then, Petrobras lost investor confidence as oil prices fell, a corruption scandal engulfed the company and losses from government fuel subsidies mounted.

Petrobras aims to cut net debt by a further $10 billion in 2019 to reach a ratio of 2 times net debt-to-EBITDA, he said. The firm will continue cutting debt until the ratio hits 1-1.5 times, he said, which would put it in line with global oil majors.

“If you look at our direct competitors and peers like Chevron, Exxon and BP, we need to look for a more light capital structure,” Grisolia said.

The firm should reach a ratio of 1.5 in 2020 as part of its next five-year business plan, he said, although that would depend on international oil prices and other variables such as foreign exchange rates.

Over the next 5-6 years, once the firm had achieved debt restructuring targets, Petrobras may consider foreign investments to facilitate exports of rising output from the development of the prolific deepwater pre-salt fields, he said.

The firm may invest in terminals abroad to receive liquefied natural gas (LNG), he said. That would help Brazil export more gas, he added.

Exxon Mobil, BP and Royal Dutch Shell RDSA.L are among firms that plan to invest billions of dollars in developing deepwater Brazilian energy reserves in coming years. Brazil is expected to account for a large share of the rise in global oil and gas output from non-OPEC countries.

OIL PRICES HELP

Oil production is expected to rise by about 8-10 percent next year from about 2.1 million barrels per day (bpd) in 2018, Grisolia said. That should contribute to increased revenue, he added.

Crude prices rallied to three-and-a-half year highs this summer as global supplies tightened, leading to higher fuel prices.

Higher oil prices than the company estimated in its 2018 budget have raised revenue and allowed Petrobras to hit its debt reduction target, he said. That compensated for the $7 billion from asset sales that Petrobras expected to receive this year, he added.

The company has already received $5 billion from sales and will receiving another $2 billion before the end of the year, he said.

“All the divestment and cash from divestment will help, but we don’t necessarily need them to achieve the target of $69 billion by the end of the year,” he said.

FUEL SUBSIDIES

Earlier this year, a nationwide truckers’ protest over rising diesel prices paralysed Latin America’s largest economy and forced the government to lower diesel prices through tax cuts and subsidies.

That hurt Petrobras’ share price as investors worried the firm would again lose cash to subsidize fuel sales.

The firm expected to receive 2 billion reais to 2.5 billion reais from the country’s oil regulator within two weeks to compensate for subsidies, Grisolia said.

Subsidies have made it less profitable for the private sector to import diesel, he said, but some imports continued and he did not foresee any fuel shortages.

“Although the volume of imports to Brazil is lower, they are not zero, they are happening.” he added. “We do recognise that margins are tighter.”

Petrobras is running refineries close to maximum capacity and importing some fuel, he said.

Petrobras has a gasoline hedge in place to cushion the impact of fuel price volatility and is considering a diesel hedge. The cost of the hedge was marginal, Grisolia said.

Banks that Petrobras typically works with for currency operations were executing the fuel hedge, he said, such as Goldman Sachs, Bank of America, Bank of Brazil and Citibank.

Petrobras has hosted meetings with economic advisors to presidential candidates ahead of wide-open elections next month. Grisolia said talks had been positive, but declined to say which teams he had met or comment on their strategies.

Candidates have different plans for the company and the role of the private sector in energy, bringing some uncertainty to investors.

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IEnova, BP Sign Contract For Liquid Fuels Terminal In Baja California, Mexico

(Sempra Energy, 11.Sep.2018) — Sempra Energy announced its Mexican subsidiary, Infraestructura Energética Nova, S.A.B. de C.V. (IEnova) signed a long-term contract with British Petroleum (BP) for the remaining 50 percent of the initial capacity of the proposed Baja Refinados liquid fuels marine terminal in Baja California, Mexico.

Under the agreement, BP will have storage capacity of 500,000 barrels of liquid fuels to supply its growing network of service stations in northern Mexico. In addition, subject to the execution of certain agreements, BP will have the option to acquire up to 25 percent of the terminal’s equity after commercial operations begin in the second half of 2020.

In April, IEnova announced it signed a long-term contract with Chevron Combustibles de México S. de R.L. de C.V for approximately 50 percent of the facility’s initial storage capacity to supply Chevron service stations and other commercial and industrial consumers.

“The Baja Refinados project is an important part of our growth strategy,” said Carlos Ruiz Sacristán, chairman and CEO of the Sempra North American Infrastructure group and chairman of IEnova. “This new terminal will increase Baja California’s energy reliability and will foster competitive prices for gasoline and other refined products on the West Coast of Mexico.”

IEnova will be responsible for the development of the liquid fuels terminal project, including financing, obtaining permits, engineering, procurement and construction, as well as maintenance and operations. The project will be located at the La Jovita Energy Hub in Ensenada and have an initial capacity of 1 million barrels of liquid fuels, with the potential for future expansion.

IEnova develops, builds and operates energy infrastructure in Mexico. As of the end of 2017, the company had invested more than $7.6 billion in operating assets and projects under construction in Mexico, making it one of the largest private energy companies in the country. IEnova was the first energy infrastructure company to be listed on the Mexican Stock Exchange.

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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.

***

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

***

Atlantic Empowers Employees for Process Safety

(Trinidad and Tobago Newsday, Carla Bridglal, 26.Jul.2018) – Atlantic CEO Dr Philip Mshelbila and BP’s vice president Group Process Safety Central Rob DiValerio 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 seventh annual Process Safety Week, hosted by LNG production company, Atlantic, for its employees and service providers at its Point Fortin liquefaction facility.

Atlantic CEO Dr. Philip Mshelbila addresses employees at Atlantic’s 7th annual Process Safety Week. Source: Trinidad and Tobago Newsday

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 launch of the 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.”

DiValerio 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.

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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.

***

BP Opens 6 Petrol Stations in Campeche

(Energy Analytics Institute, Jared Yamin, 10.Jul.2018) – British Petroleum extended its operations in the country this week.

Today, we have arrived to Campeche, a state with an increase in tourist activity, reported the daily, citing BP Fuels Mexico General Director Alvaro Granada.

The British company initiated activities in Campeche with inauguration of an initial six of 10 planned petrol stations for this year in the state, reported the daily newspaper La Jornada.

In less than a year and a half, BP has emerged as the foreign company with the largest presence in Mexico. The company already covers an estimated 50% of the national territory, and operates nearly 300 petrol stations where it receives more than 500,000 customers daily.

“BP has come to offer a network of service stations that exceed the expectations of consumers in Campeche,” added Granada.

The inauguration of these first six petrol stations in Campeche and plans to open four more this year in the state form part of the company’s business plan to reach a network of 1,500 petrol stations by 2021.

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Argentina to Free Retail Fuel Prices

(Reuters, Luc Cohen, 1.Jul.2018) – Argentina will allow fuel retailers to freely set pump prices starting in August, according to an Energy Ministry official familiar with the plan, a move that could encourage badly needed investment in the nation’s oil patch but risks worsening sky-high inflation and angering consumers.

Separately, the ministry is looking to set up an auction process for the natural-gas market that it hopes will lower prices, according to the official, who was not authorized to speak publicly.

The actions signal that President Mauricio Macri is moving ahead with free-market reforms to attract private investment to develop the nation’s abundant shale oil reserves, even as rising global oil prices and a precipitous weakening of the nation’s currency have led to pressure for more interventionist government policies.

The moves will also bring relief to the oil sector. Price controls have squeezed refiners’ margins, prompting one refinery to suspend operations.

Macri’s pro-business government freed fuel prices last year, part of its efforts to unwind state controls on Argentina’s economy. But his administration reversed course in May due to a rapid decline in the peso. The sudden depreciation rattled markets and prompted Argentina to turn to the International Monetary Fund (IMF) for emergency financing.

In May, the government reached a deal for a two-month freeze on pump prices with the three largest oil companies operating in Argentina: state-owned YPF, Shell, and BP’s Pan American Energy. It later set the price of domestic crude at $68, about $10 below the global Brent crude price, to mitigate the impact of freezing fuel prices on refiners’ margins.

By freeing pump prices, the government is betting that gas stations will limit price hikes to avoid losing customers, the official said, and that by freeing crude prices it would encourage more investment in domestic drilling, part of a long-term strategy to wean Argentina from petroleum imports.

“Price controls do not help with anything,” the official said.

The government and the oil companies agreed to loosen the freeze June 1, allowing for hikes of 5 percent in June and 3 percent in July. Macri’s administration had kept the industry guessing as to what it might do in August.

The earlier increases were unsatisfactory to oil industry players, three of whom complained privately to Reuters that the modest bumps did not come close to covering their increased costs.

Last month, global trader Trafigura announced it was suspending activities at its 30,500 barrel-per-day refinery in the port city of Bahia Blanca due to the “mismatch between fuel prices and production and import costs.”

An oil industry executive who spoke with Reuters recently expressed frustration with the bind.

“The adjustment that needs to be done is not 3 percent, it is 45 percent,” said the person, who requested anonymity to speak freely.

VACA MUERTA RAMP-UP

An end to retail price caps would likely infuriate Argentine consumers, who are already incensed at the government for the drop in the peso and inflation that is running at a 26.3 percent annual clip.

But Macri’s government has prioritized reviving the energy sector to shake Argentina’s dependence on imported oil and gas, and to put an end to market-distorting subsidies.

Argentina possesses the world’s second-largest reserves of shale natural gas and ranks No. 4 in reserves of shale oil, mostly in the Vaca Muerta fields in Patagonia. But it faces stiff competition to attract the billions in private investment needed to develop these resources. Oil production is languishing at multi-decade lows.

The picture is brighter with natural gas. Rising output in Vaca Muerta helped boost the country’s production by 3.4 percent in the first quarter of 2018 compared with the same period last year, according to government data.

“We are beginning to have an abundance of gas in Argentina,” the Energy Ministry official said.

As a result, the ministry will create an auction process for wholesale customers to bid on the open market for their natural gas supplies during the low-demand summer months, the official said. The plan is to phase out the current fixed-contract system in a move the government hopes will lower prices.

The auctions could start in September or October, and could account for as much as 70 percent of wholesale supply by March or April of 2019, the official said.

Argentina is also expected to begin gas exports to Chile in the fourth quarter of this year, another result of rising Vaca Muerta output.

Argentina will still need to import liquefied natural gas (LNG) to meet demand in winter months.

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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.
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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.
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BP Projects Higher Future Cash from T&T

(By Trinidad Express, Aleem Khan, 22.May.2018) — BPTT’s standardized measure of discounted future net cash flows for 2017 was updated to US$3.3 billion in the company’s annual report released earlier this month.

Up from US$909 million in 2016, and US$1.8 billion in 2015, BP cautioned: “Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of future production, the estimation of crude oil and natural gas reserves and the application of average crude oil and natural gas prices and exchange rates from the previous 12 months.

Full story access requires subscription to Trinidad Express.

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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.
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Claire Fitzpatrick, First Female to Lead BPTT

(BPTT, 1.May.2018) – Mrs. Claire Fitzpatrick has been appointed as Regional President of BP Trinidad and Tobago (BPTT). In this role, Mrs. Fitzpatrick will be accountable for BPTT’s performance and BP’s business interests in Trinidad and Tobago. She is the first female to lead BPTT, which produces approximately 15% of the BP group’s global production.

Mrs. Fitzpatrick holds a BSc in biological sciences from the University of Edinburgh and is a fellow of the Institute of Chartered Accountants in England and Wales. She joined BP from Ernst & Young in 2002 as chief accountant, upstream and since then has held commercial and leadership roles in BP’s upstream business. Mrs. Fitzpatrick has also worked in BP’s corporate centre and most recently managed BP’s upstream joint venture in Australia.

Mrs. Fitzpatrick is honored to lead BPTT: “I look forward to working with the BPTT team and stakeholders to the mutual benefit of Trinidad and Tobago and BP.”

Note to editors:

BPTT has 14 offshore platforms and two onshore processing facilities.

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Echo Energy Sees Favorable Investment Ops in Argentina

(Energy Analytics Institute, Ian Silverman, 1.May.2018) – “Argentina offers favourable investment opportunities in the upstream sector. A historical lack of investment means the country is now reliant on imported gas to feed its growing economy. The country is opening itself to foreign investment in a bid to replace reserves and halt the decline in domestic production,” announced London-based Echo Energy on its website.

“Argentina’s gas industry began in the 1960’s and has developed the country into a gas-intensive economy where 50% of its primary energy demand is now met by natural gas (BP Statistical Review of World Energy, 2017). Declining costs of credit default swaps (Reuters, 2017) related to an improving political and fiscal environment, only add to the attractiveness of the region,” the company added.
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Dominican Republic to Join Caribbean Energy Rush

(Bloomberg, Ezra Fieser, 5.Mar.2018) – The Dominican Republic expects to draw interest from energy titans BP Plc and Exxon Mobil Corp. when it opens the country to natural gas and oil exploration for the first time later this month, joining a push by governments across the Caribbean to develop energy production.

The government plans to open two land blocks for oil exploration and two offshore blocks for natural gas exploratory drilling by the end of March, said Energy and Mining Minister Isa Conde in an interview in Santo Domingo. An Exxon spokeswoman said in an email that the company does not comment on future business plans. BP did not respond to an email seeking comment.

“This is completely virgin territory for us,” Conde said. “But we would not be going forward if we had not received assurances from international companies and investors that there was substantial interest.’’

Developing the industry would give the nation of 11 million another source of foreign exchange earnings and allow it to cut its fuel import bill, Conde said. Although few Caribbean islands have developed significant commercial production outside of Trinidad & Tobago, a top exporter of liquefied natural gas in the Americas, the region is rapidly drawing interest from energy companies.

Exxon is leading a group of companies developing 6.6-million-acres in Guyana’s waters that could make the country one of Latin America’s largest oil producers within a decade. That discovery has spurred interest in neighboring Suriname, while the government in the Bahamas is also opening offshore areas for exploration. In Jamaica, CGG GeoConsulting and the Petroleum Corporation of Jamaica said last month they had discovered oil seeps in two separate parts of the island.

Seismic study

The Dominican government does not have an estimate of the reserves and Conde said any production could be years away. A two-year seismic study found six areas that potentially hold light and heavy crude or natural gas. If the areas prove commercially viable, the government will likely demand production contracts in which it continues to own the land, he said.

The $72 billion economy is forecast to grow 4.5 percent this year, the most in Latin America after Panama, according to economists surveyed by Bloomberg.

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Vaca Muerta Megaproject – A Fracking Carbon Bomb In Patagonia

(Observatorio Petrolero Sur, 5.Feb.2018) — Vaca Muerta is a leading case for the next generation of fossil fuels. Big Oil and Gas companies are keen to turn it into a success story —which is why we collectively need to put a stop to this if we are serious about restricting oil and gas supply globally, protecting territories and fighting climate change. It is our view that “Killing the Dead Cow”—and thus preventing a further expansion of the fossil fuel industry that would be a door-opener for further projects in the Global South— is necessary to build up pressure for an honest dialogue about “managed decline” and fair transition. The collective success of movements in an emblematic case like this would increase leverage for such a conversation.

Briefing: Vaca Muerta shale play – climate impacts, wealth concentration and human rights abuses.

Argentina ranks in second and fourth place globally in shale gas and shale oil resources. Almost all of this potential is concentrated in “Vaca Muerta” (“Dead Cow”), which has been identified as the biggest shale play outside North America and makes Argentina the third country, after the United States, and Canada, to reach commercial development. Vaca Muerta is presented as a test case for the Global South, and especially for the Latin American region, where several governments are proposing new unconventional projects.

Total estimated resources amount to 19.9 billion barrels of oil and 583 trillion cubic feet of gas. They represent around 50 billion tons of CO2 that are currently locked in the ground which can only be extracted with hydraulic fracturing (or fracking), a highly controversial technique which has been banned in several countries or sub-national entities.

Although it is still at an early stage of development (2 to 4%, 1,500 fracking wells), almost every oil major is present in the region. Ventures include YPF, Chevron, Total, Dow Petrochemical, Petronas, Schlumberger, Shell, Pan American Energy (BP, CNOOC, and Bridas), Wintershall, Statoil, Gazprom, and ExxonMobil.

International involvement is crucial for funding (estimated at tens of billions of dollars), capacity building and governance. Other involved actors include U.S. Department of State, World Bank, Inter-American Development Bank, Citibank, ICBC, and Deutsche Bank.

Regulation and policy enforcement is scarce. Its early development is currently infringing on a range of individual and collective human rights in working-class neighborhoods, indigenous communities, agriculture regions, and protected areas. Fracking is an experimental technique so various accidents have been recorded: radioactive pills have been lost in wells, wells have gone up in flames due to gas leaks, truck accidents have caused spills, pipelines have broken, and five workers lost their lives, among other incidents. Social impacts are also exacerbated.

Vaca Muerta is a complex, multidimensional and global issue. It seems unstoppable, but the venture has shown great structural intrinsic fragility and its real potential has been overhyped. On top of that, its scope and speed have also been reduced by networks of national and international resistance. Across the country, numerous bans on fracking and infrastructure projects have been obtained.

Download the project brief here

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#LatAmNRG

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.

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Mexico Tops BP Growth Plans

(Reuters, Jessica Resnick-Ault, 17.Jan.2018) – BP is expanding its retail presence with plans to open 3,000 branded retail stations globally in the next five years, half in Mexico, as that market becomes increasingly open to international business.

The company already has over 100 retail outlets in Mexico, many operated by distributors that previously worked for Mexico’s state-owned oil company Pemex.

Energy reforms ended Pemex’s nearly 80-year monopoly several years ago and opened Mexico’s gasoline stations to international investment from the likes of Exxon Mobil Corp, Valero Energy Corp and Andeavor. Trading firm Glencore announced plans last year to start importing fuel for Mexico’s domestic market.

“We are looking at all different kinds of operations there,” Rick Altizer, BP senior vice president of sales and marketing said on Wednesday. He said they are open to waterfront terminals, rail operations or other logistical assets to supply its stations.

BP is also in the process of opening 10 stores in the U.S. Northeast under the Amoco brand, which it had previously retired. The Amoco label allows BP to expand in areas already saturated with BP stations, and appeals to customer nostalgia for the older label, Altizer said, speaking at an Amoco station in Pelham, New York. The label will also be used in other parts of the country.

The company expects global demand growth of 2.4 percent this year and 1.7 percent in 2019 even as automotive efficiency improves, he said.

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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.

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Venezuela Holds World’s 8th Largest Gas Reserves

(Energy Analytics Institute, Piero Stewart, 11.Mar.2017) – Venezuela, the country with the world’s largest crude oil reserves, also continues to hold the world’s eighth largest accumulation of natural gas reserves (see table below), according to BP’s Statistical Review of World Energy.

Top Ten Holders of Natural Gas Reserves Worldwide

Rank —- Country ———————- Natural Gas Reserves (Tcf)

1 ——— Iran ————————– 1,201.4

2 ——— Russia ———————– 1,139.6

3 ——— Qatar ———————— 866.2

4 ——— Turkmenistan ————– 617.3

5 ——— USA ————————- 368.7

6 ——— Saudi Arabia ————— 294.0

7 ——— United Arab Emirates —- 215.1

8 ——— Venezuela * ————— 198.4

9 ——— Nigeria ——————— 180.5

10 ——- Algeria ———————- 159.1

Source: BP

Note: PDVSA reported that Venezuela’s natural gas reserves were 201.349 trillion cubic feet (Tcf) at year-end 2015, the last time the company reported annual auditing operational data. Of this total, 64.916 Tcf corresponded to associated gas in the Hugo Chávez Heavy Oil Belt, and 36.452 Tcf corresponded to associated gas related to extra heavy oil in Venezuela’s Eastern Basin, according to PDVSA data.

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Big Oil Flocks To Argentina As Permian Land Prices Skyrocket

(Oilprice.com, Charles Kennedy, 15.Sep.2016) — The Permian Basin has become so hot that some oil companies are starting to stay away, instead looking at frontiers that are less picked over.

BP is one such company. The British oil giant’s CEO Bob Dudley said that land in the Permian has become too expensive, and instead he is looking to expand operations in Argentina, where the vast Vaca Muerta shale basin offers appetizing opportunity.

In an interview with Bloomberg TV from Buenos Aires, Dudley said BP is planning on acquiring more assets in the Vaca Muerta. And it isn’t just the “enormous potential” from the oil and gas reserves in the shale basin, but also the friendly policy put forth by the new Argentine government led by President Mauricio Macri. “I’m really encouraged by what I see,” Dudley said. “There’s a lot of future here.” BP has a joint venture with Bridas Corp. – BP owns 60 percent of Pan American Energy LLC and Bridas controls the other 40 percent. BP will expand its presence in Argentina through this JV.

Argentina is quickly becoming one of the few countries that has achieved shale development outside of North America. One of the biggest incentives the government has offered is regulated oil prices, set at levels higher than the international price. Several of BP’s peers are already drilling in the Vaca Muerta, including Chevron, ExxonMobil, and Royal Dutch Shell.

The state-owned YPF said that it would need investments totaling about $200 billion to fully exploit the Vaca Muerta.

Exxon said earlier this year that it might spend more than $10 billion in Argentina, building on several pilot projects. The investments would span decades. “I am very encouraged by the changes that have occurred here in Argentina, with the change in government,” Exxon’s CEO Rex Tillerson said in June. More and more companies are starting to build up their presence in Argentina.

Meanwhile, back in Texas, land prices are shooting through the roof. SM Energy recently spent more than $39,000 per acre for land in the Permian, which some are calling the “hottest zip codes in the industry.” That is pricing out some companies and forcing many to look elsewhere. With West Texas saturated with drillers, Argentina stands to benefit.

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Energy Analytics Institute (EAI): #LatAmNRG

Venezuela Still the Country with the Largest Oil Reserves

(Energy Analytics Institute, Pietro D. Pitts, 14.Aug.2016) – Venezuela, the resource-rich South American country known for its chocolates, Caribbean beaches, lively citizens and beauty queens, still reigns as the country with the largest crude oil reserves, according to the BP Statistical Review of World Energy (June 2016).

Venezuela had proved oil reserves of 300.9 billion barrels at year-end 2015 and a reserves-to-production (R/P) ratio of 313.9 times based on production of 2.626 million barrels per day in 2015, according to the review.

Said another way, Venezuela has enough crude oil reserves to last it for 313.9 years.

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Petrobras Reports New Campos Basin Find

(Petrobras, 4.Feb.2015) – Petrobras announced the discovery of new oil accumulations in concession BM-C-35 (exploratory block C-M-535), located in the Campos Basin postsalt layer.

The discovery was made while drilling well 1BRSA-1289-RJS (ANP nomenclature) / 1-RJS-737 (Petrobras nomenclature), informally known as Basilisco.

The well is situated some 143km from the city of Armação dos Búzios, on the coast of Rio de Janeiro state, at a water depth of 2,214 meters. The accumulations consist of heavy oil and can be found in two different reservoir depths, at 3,190 meters and at 3,521 meters.

The consortium of concession BM-C-35, which includes Petrobras (operator, 65% WI) in partnership with BP (35% WI), will proceed with the necessary activities to assess the extension of the discoveries, as well as the concession’s exploratory potential.

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Bolivia’s Nationalization of Oil and Gas

(Council on Foreign Relations, Carin Zissis, 12.May.2006) — In a region seen as turning leftward, forging alliances would seem a natural course of events. But Bolivian President Evo Morales’ decision to nationalize the oil and gas industry is exposing tensions, causing experts to say there is more diffusion than alliance-building in Latin America.

Introduction

On his hundredth day in office, Bolivian President Evo Morales moved to nationalize his nation’s oil and gas reserves, ordering the military to occupy Bolivia’s gas fields and giving foreign investors a six-month deadline to comply with demands or leave. The May 1 directive set off tensions in the region and beyond, particularly for foreign investors in Brazil, Spain, and Argentina. Morales’ nationalization agenda has been described as another chapter in Latin America’s turn to the left, and fears are rising that the Bolivian leader has fallen into the fold of Venezuela’s Hugo Chávez and Cuba’s Fidel Castro. But some experts emphasize there may be more infighting than cohesion overall in the region.

Why did Morales nationalize Bolivia’s hydrocarbon industry?

Morales, a former coca farmer and union leader, won a resounding victory in the December 2005 elections. As the Movement to Socialism (MAS) candidate, he campaigned in favor of nationalizing, among other sectors of the economy, the gas and oil industries with the cooperation of foreign investors. Experts say that, given such promises, the nationalization was no surprise. But Peter DeShazo, director of the Center for Strategic and International Studies’ Americas Program, says the move to occupy the gas fields with military forces lent a dramatic effect. “The confrontational nature of his move was certainly intended to get people’s attention,” he says, adding that Morales may be looking to garner votes in July elections for a constituent assembly that will redraft Bolivia’s constitution.

Nouriel Roubini, a professor of economics and international business at New York University, says one explanation for nationalization is ill will over encroachment on Bolivia’s territory by its neighbors. Since gaining independence in 1825, the Andean nation lost ocean access to Chile, as well as land to Brazil, Paraguay, and Peru. “There is this kind of historical resentment,” Roubini says, adding that Bolivians “are giving a slap in the face to Brazilians and Spaniards.” Morales echoed this sentiment at a May 11 summit of Latin American and European leaders, where he reaffirmed his energy-nationalization plans and signaled his government would seize large land holdings. Experts say this could also affect Brazil, whose farmers have major land holdings in Bolivia.

In spite of having the region’s second largest natural-gas reserves after Venezuela, Bolivia is among Latin America’s poorest nations. The landlocked country has also been marked by political instability; six presidents have held office in as many years, and one of them, Gonzalo “Goni” Sánchez de Lozada, was forced to resign in 2003 after protests against plans to export Bolivian gas turned violent. Among the free trader’s opponents was Morales, who said foreign investors received too much in gas-sale profits based on the hydrocarbons law in place at the time.

How will the nationalization plan work?

Morales’ May 1 decree states that foreign companies, which have invested almost $4 billion since Bolivia opened up its energy sector in the late 1990s, must hand majority control over to state-owned Yacimientos Petrolíferos Fiscales Bolivianos (YPFB). Firms have 180 days to renegotiate energy contracts with the Bolivian state, which experts say will likely lead to price increases. During that time, the companies which own the two largest oil fields will absorb a 32 percent hike (82 percent total) in royalties and taxes. Bolivia, which has 55 trillion cubic feet of natural gas, is expected to see a jump from $320 million to $780 million in annual oil-related revenues, and has installed new directors representing YPFB on the boards of foreign firms’ local subsidiaries. While negotiations occur, Bolivia will conduct an audit of the foreign companies. Morales recently warned foreign companies they will not be compensated if they have recovered their original investments.

Who stands to lose from the nationalization policy?

The firms with the largest holdings in Bolivia’s energy industry are the Spanish-Argentine venture Repsol YPF and Brazil’s Petrólio Brasileiro (Petrobras). Britain’s British Petroleum (BP) and France’s Total also have large investments. Repsol YPF has invested some $1.2 billion in Bolivia’s energy industry, and Argentina’s President Nestor Kirchner, whose country faces double-digit inflation rates, is concerned about rising gas prices jeopardizing Argentina’s economic recovery. But Brazil is under the greatest pressure if prices go up, as Bolivia provides it with about half of its gas. In the populous economic center of Sao Paolo that figure is closer to 75 percent. Petrobras has invested $1 billion in Bolivia’s natural-gas industry. Morales’ move has put Brazilian President Luiz Inácio Lula da Silva in a vulnerable position in the months leading up to his October reelection bid.

What are the reactions to Morales’ plan?

While foreign companies said they hope for cooperation, Repsol YPF has said it will act to protect its investments and take legal action if necessary. Petrobras has made similar threats and frozen investments. Experts say Bolivia needs investors such as Petrobras, which accounts for roughly 20 percent of the country’s gross domestic product (GDP) and 24 percent of its tax revenue. John Williamson, senior fellow at the Institute for International Economics, says Bolivia may see short-term gains but in the long term, it’s going to lead to less foreign investment. He also cautions that Morales’ move could cause divisions in the region.

Is Bolivia’s nationalization testing regional alliances?

Yes, say some experts. CFR Senior Fellow Julia Sweig says that Lula has been more silent in coming out against the nationalization than Spain’s President José Luis Rodríguez Zapatero because Lula—a former trade union leader like his Bolivian counterpart—is “sympathetic” to Morales’ intentions. Diego von Vacano, assistant professor of political science at Texas A&M University and a Bolivian national, says, “Lula wants to prevent a sort of face-off with Morales” because he “doesn’t want to destabilize the region.”

Yet, not all Latin American leaders who are leaning to the left are the same, experts say. “On one side, you have a number of administrations that are committed to moderate economic reform,” says Roubini. “On the other, you’ve had something of a backlash against the Washington Consensus [a set of liberal economic policies that Washington-based institutions urged Latin American countries to follow, including privatization, trade liberalization and fiscal discipline] and some emergence of populist leaders.” Among the latter group is Venezuela’s Chávez, an outspoken opponent of the Bush administration; DeShazo of CSIS calls Chávez Latin America’s “high priest” of economic nationalism.

What is Morales’ relationship with Chávez?

Just before the May 1 decree, Morales met with Chávez and Castro in Havana to sign a socialist trade agreement that made Morales a member of the Bolivarian Alternative for the Americas. The three are now calling it the “Axis of Good,” a pact originally signed by Chávez and Castro last year. Morales and Chávez threatened to pull out of the Andean Community if Colombia, Peru, and Ecuador sign free trade agreements with the United States. Castro and Chávez also said they would become Bolivia’s primary soybean importers. This plan may affect Brazil, because Morales has set a May 31 deadline for land redistribution in the Santa Cruz region, where Brazilian farmers grow more than a third of Bolivia’s soybeans and have invested heavily in land and agriculture.

But experts caution that it is not yet clear where Morales’ alliance falls. Sweig says “the embrace he’s getting from Chavez is getting harder and harder to resist,” but he also “understands that he has to function in a global context and not just an Andean one.” Sweig adds, “Bolivia is going to tack one way one day and one way the other.” There are also signs of infighting rather than a growth in alliances in the region. The Andean Community is not the only trading bloc with members threatening to bow out; in April, Uruguay warned it may leave Mercosur, the Southern Cone trading bloc, and suggested Paraguay is a partner on this. Williamson says the region “is more divided than I’ve ever seen it.” Sweig echoed this, saying, “I just don’t see the kind of diplomatic skill and institutional capacity to do alliance building. It’s not like the EU.”

What is the U.S. role in Bolivia and in the region?

Experts say the United States has paid less attention to Latin America after September 11, 2001, particularly as events have heated up in the Middle East. Meanwhile, Roubini says the situation in the region is “developing in such a way that is actually dangerous to U.S. interests.” According to Von Vacano, this period of crisis diplomacy between countries in the region would be a good time to become more engaged, and that the United States is “missing a chance to be a kind of broker, to get involved in South America without being heavy-handed.” Williamson says the United States should maintain an open hand to negotiate free trade agreements but “any U.S. influence is resented so much that it is counterproductive.” Sweig says the United States should tread carefully because intentions to influence outcomes can backfire. She points to Bolivia’s 2002 election, when the U.S. Ambassador Manuel Rocha urged Bolivians not to vote for Morales, who then surged in the polls and almost defeated Sánchez. The problem, Sweig says, “is when we say ’democracy,’ Latin Americans hear ’imperialism.’”

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