YPFB To Build Five Satellite Regasification Stations

(Energy Analytics Institute, Jared Yamin, 18.Oct.2018) — Yacimientos Petrolíferos Fiscales Bolivianos (YPFB) plans to build five satellite regasification stations (ESR) that will benefit 12 populations of La Paz, Potosí, Chuquisaca and Santa Cruz.

YPFB will move forward with the five ESR projects, which will benefit 12 communities located in La Paz, Potosí, Chuquisaca and Santa Cruz, announced Bolivia’s state oil entity in an official statement on its website.

These projects are in addition to 27 ESRs that already operate across the country, YPFB said, citing Executive President Oscar Barriga Arteaga.

A YPFB LNG Plant, the first of its kind in Bolivia, is located in Rio Grande, Santa Cruz and distributes gas to ESRs through cryogenic tanks. The plant’s production capacity is 210 metric tons per day (TMD) of liquefied natural gas. The ESRs receive natural gas supply for domestic, industrial, commercial and vehicular natural gas consumption, YPFB said.



Argentina Plans To Close LNG Importing Facility

(Bloomberg, Jonathan Gilbert, 17.Oct.2018) — Argentina plans to close a facility for importing liquefied natural gas (LNG), according to people with direct knowledge of the matter, after booming production from shale deposits in the Vaca Muerta region turned the country into a seasonal exporter.

A contract with Excelerate Energy, which has a regasification ship moored at the Atlantic port of Bahia Blanca, won’t be renewed when it expires at the end of the month, said the people, who asked not to be named because the decision isn’t yet public. Argentina will continue to import LNG at another facility in Escobar, on the River Plate estuary, the people said.

YPF SA, the state-run oil company that manages the contract, declined to comment on the decision. A spokeswoman for Excelerate didn’t immediately comment.

The decision not to renew the decade-old contract comes as output from Vaca Muerta, the nation’s answer to the Permian basin, has created an oversupply of gas during the summer. Shale gas production soared to 205 million cubic meters a day in August, more than triple the level seen a year earlier. The government has negotiated exports to Chile to help solve the problem. It has also initiated talks to receive less gas from neighboring Bolivia, with which it has a contract through 2026.

Three Cheniere Energy tankers were set to unload at Bahia Blanca this year through May, according to the latest official import schedule.



Bolivia’s Oil Revenue To Reach $2.2 Billion

(Xinhua, 14.Oct.2018) — Bolivia’s oil revenue this year is estimated to reach 2.2 billion U.S. dollars as it “will be able to fulfill” contracts with its southern American partners, Minister of Hydrocarbons and Energy Luis Alberto Sanchez said Saturday.

“The income to the country is guaranteed,” Sanchez said. “We should feel certain about the expected income from the export of gas because we will be able to fulfill the contracts with Argentina until 2026 and with Brazil for the remaining volume to be delivered and an extension of the contract until 2024.”

Bolivia is negotiating an increase in gas sales in western Brazil, the minister said, adding that it is negotiating with new markets that will generate greater benefits through direct sale of natural gas to several Brazilian states.

“This is good for us because it opens up the Brazilian market. The country has all the right conditions to take on these new contracts and at better prices,” he said.

Bolivia is working on the export of liquefied natural gas (LNG) by way of the Peruvian port of Ilo on the Pacific coast, the government confirmed Saturday.

The deal with Paraguay is under negotiation to supply gas to the Chaco region, a sparsely inhabited area, both at the household level and for the generation of electricity, according to Humberto Salinas, vice minister of Industrialization, Commercialization, Transportation and Hydrocarbon Storage.

“We will be exporting to Paraguay and we will end up opening new overseas markets with the liquified natural gas,” Salinas said.

Bolivia is a major exporter of LNG in South America, with 99 percent of the exports going to Paraguay and Peru, the vice minister said, adding that it hopes to add Uruguay, Argentina and Brazil to the list of export destinations.

Between 1985 and 2005, Bolivia earned 4.587 billion dollars in oil revenue, at an average of 225 million dollars a year. From 2006 to 2015, the total reached 31.573 billion dollars, with a yearly peak of 5.489 billion dollars in 2014.

Bolivia’s GDP growth declined from a peak since the 1970s of 6.8 percent in 2013 to an estimated 4.2 percent in 2017 due to a less favorable international environment and a temporary reduction in the external gas demand, according to the World Bank.


Energy Analytics Institute (EAI): #LatAmNRG

Bolivia’s Gas Lower than LNG, Vaca Muerta Shale: Sánchez Says

(Energy Analytics Institute, Jared Yamin, 12.Oct.2018) — Bolivian natural gas is more competitive than liquefied natural gas (LNG) and gas from Argentina’s Vaca Muerta shale formation, announced Bolivia’s Hydrocarbon Minister Luis Alberto Sánchez.

The minister stressed that Bolivian gas, priced at $7/MMbtu, was much cheaper than Argentine gas.

Argentina’s LNG imports cost around $10.50/MMbtu, while the production cost in Vaca Muerta is around $7.50/MMbtu, so “the most competitive gas for the Argentine market is undoubtedly Bolivian gas,” reported the daily newspaper El Diario, citing Sánchez.

Sánchez warned that if Argentina decides to pay a lower price (reduces the price), it must pay the Take or Pay (contract modality), which establishes a fine be paid for any energy not withdrawn, plus interest.


Energy Analytics Institute (EAI): #LatAmNRG

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.


Excelerate Energy, TGS Sign Deal to Study Liquefaction Project in Bahía Blanca

(Excelerate Energy L.P., 10.Sep.2018) — Excelerate Energy L.P. and Transportadora de Gas del Sur S.A. announced the execution of a Memorandum of Understanding to jointly collaborate on the assessment of a liquefaction project in the city of Bahía Blanca, Argentina. Argentina currently imports liquefied natural gas (LNG) through two floating import terminals, particularly during the country’s peak winter consumption. The successful development of Argentina’s shale gas reserves resulted in a potential excess of natural gas during the summer months. The project aims at studying the technical and commercial viability of liquefying and exporting natural gas during the summer season, allowing a more sustainable development of shale gas resources and reducing Argentina’s annual natural gas net import needs. The study is expected to be completed by the end of 2018, at which time Excelerate and TGS will share the results with government and industry officials and decide on further actions towards the implementation of the Project.

“Given the high seasonality of Argentina’s natural gas consumption, LNG has played a critical role in meeting the country’s energy demands,” stated Excelerate’s Chief Commercial Officer Daniel Bustos. “This Project will significantly enhance Argentina’s capacity to maximize the use of local resources by allowing a more predictable development of shale gas production while reducing the overall costs of importing LNG.”

TGS is carrying out an important midstream project aimed at the transportation and conditioning of the natural gas production derived from the Vaca Muerta Basin, located in the province of Neuquén, Argentina. This Project represents an essential contribution to the development of shale gas reserves, promoted by the National and Provincial Governments, as it will ensure the infrastructure required to inject incremental gas production to the main transportation systems.

“Carrying out LNG production through the Project will be key to promote the development of unconventional gas, since it will allow to expand the scale of the gas market, increasing export opportunities, after having met domestic market needs in Argentina,” stated TGS’ Chief Commercial Officer Néstor Martín.

Both Excelerate and TGS have been critical players in the growth of the Argentine energy industry. Currently, one hundred percent of LNG imported and regasified into the country is through Excelerate’s two floating storage and regasification units (FSRUs). Excelerate developed South America’s first LNG import terminal in 2008 in Bahía Blanca, following with the second terminal in 2011 in Escobar, Argentina. TGS is the leading natural gas transportation company in Argentina and owns and operates South America’s largest pipeline network. The project underscores both party’s commitment to seeing Argentina’s energy sector become more sustainable for the long term.


New Fortress Builds On LNG Presence With Irish, Mexican Projects

(LNG World Shipping, Mike Corkhill, 4.Sep.2018) — New Fortress Energy has added two major LNG import projects to its portfolio, as part of its drive to bring the benefits of clean-burning gas to new markets

New Fortress Energy (NFE) has agreed to buy a site at Ballylongford in Ireland’s County Kerry with the intention of constructing a new LNG receiving terminal. The proposed €500M (US$581M) facility has already been awarded the necessary planning permission and was recently designated an EU Project of Special Interest by the European Commission.

The project, termed Shannon LNG, has been under consideration for several years but the conditions have not been deemed amenable for a final investment decision on Ireland’s first LNG import terminal.

Circumstances are now changing, however. On the one hand, the European Commission is putting pressure on EU member countries to substitute clean-burning gas for coal in power generation under its increasingly rigorous environmental programme. And on the other, the possibility of the UK’s imminent departure from the EU occurring as a “hard Brexit” is raising the prospect of higher charges for UK pipeline supplies, currently Ireland’s only source of natural gas, due to regulatory divergences.

NFE and its backers are likely to rely on public funding to cover up to half the cost of the Shannon LNG project. The scheme would be the company’s largest play in the LNG sector to date.

To be situated on the south side of the Shannon Estuary on Ireland’s west coast, the terminal will have the capacity to process 3 mta of LNG and will feature four 200,000-m3 LNG storage tanks and a jetty able to accommodate LNG carriers of up to 266,000 m3. Shannon LNG also has planning permission to build an adjacent 500-MW gas-fired combined heat and power plant.

Down Mexico way

NFE has been increasing its commitment to bringing LNG to new markets this year. Earlier in August 2018, just two weeks before breaking the news about Shannon LNG, NFE was awarded a long-term contract by Mexico’s Port Authority of Baja California Sur (APIBCS) to develop, construct and operate an LNG import terminal at Pichilingue.

Pichilingue is located close to La Paz near the southeastern tip of Baja California. Mexico’s southern Baja California state currently lacks any natural gas infrastructure.

The contract announcement coincided with the start of work at the terminal site. The US$185M facility should be in service by 2020. Although NFE and APIBCS provided no details of the terminal on announcing the scheme, the project’s cost and timing indicate an LNG receiving terminal based on using a floating storage and regasification unit (FSRU).

LNG regasified at the terminal will be utilised locally, including as a substitute fuel for oil in the region’s power plants. Road tanker loading bays to be provided adjacent to the jetty will enable the distribution of LNG to nearby vehicle fuelling stations and LNG bunkering jetties.

Outside of Mexico, NFE developed an LNG project in Jamaica in 2016 for Jamaican power utility JPS, to supply the 120-MW Bogue power station at Montego Bay on the north side of the island. This was NFE’s first involvement in an LNG project and to meet its commitments the company chartered 138,000-m3 Golar Arctic for two years for use as a floating storage unit (FSU) and 6,500-m3 Coral Anthelia to shuttle LNG to the power plant.

Jamaica is seeking to press ahead with substituting oil with gas in power generation to the greatest extent possible. New customers for gas are being lined up and JPS has requested an enhancement of the country’s LNG-processing capabilities. In response NFE is chartering Golar LNG Partners’ 126,000-m3 FSRU Golar Freeze, for 15 years, commencing in Q4 2018, for stationing at Port Esquivel on the south side of the island, to the west of Kingston.

Gas from Golar Freeze will be piped ashore to fuel the new 190-MW Old Harbour Bay power plant. Some LNG will be transhipped from the FSRU to a shuttle tanker and transported to the upgraded, 140-MW Bogue power station. A third gas-fuelled plant, of 94 MW, is being built in Clarendon for the Jamalco bauxite company.

Fortress affiliates

NFE is controlled by the New York-based investment management firm Fortress Investments Group LLC. American LNG Marketing, an affiliate company, is also involved in the LNG sector through its shipment of LNG in ISO tank containers to islands in the Caribbean.

American LNG operates a small liquefaction plant in the Florida town of Medley near Miami. The company dispatched its first LNG tank container export shipment from this plant, known as Hialeah, in February 2016.

Hialeah has been approved for exporting up to 66,000 tonnes per annum of LNG in tank containers to countries with which the US does not have a free trade agreement. Natural gas for the facility is supplied by Peninsula Energy Services.

Between February and June 2018 American LNG Marketing handled 110 tank container shipments of LNG to Barbados and 50 to the Bahamas. The tanks were loaded onto ships berthed at Port Everglades in southern Florida.

Florida East Coast Railway (FECR), operator of 550 km of track linking the state’s eastern ports, from Jacksonville in the north to Miami in the south, is another Fortress Investments Group company. Both the Hialeah LNG plant and Port Everglades have intermodal terminals and FECR trains are used to shuttle laden and empty American LNG Marketing tank containers between the two facilities.

FECR is also using LNG as a locomotive fuel. Each train is powered by a pair of suitably modified locomotives while the fuel tender is comprised of a 40-foot LNG tank container mounted on a heavy-duty flat car. Such trains, which run on an 80/20 LNG/diesel mix, can make a return journey along the full length of the FECR line before an LNG fuel refill is required.


Trinidad: Crouching Tiger

Trinidad and Tobago Prime Minister Keith Rowley and Venezuela’s President Nicolas Maduro during the Dragon gas signing event in Caracas. Photo: PDVSA

(Trinidad and Tobago Newsday, Kiran Mathur Mohammed, Camille Moreno, 30.Aug.2018) — The Dragon gas deal signed last Saturday is worth celebrating. The clink of glasses will be heard in boardrooms in both countries. The government deserves it for getting this far, amid the chaos in Venezuela, and the spectre of international sanctions.

At least one senior banker I’ve spoken to noted that the agreement rings hollow for Venezuelans on Maduro’s Twitter feed who mocked the grand signing ceremony, as thousands of hungry and desperate refugees flee to Trinidad. Instability there may still upset the deal’s execution, and could result in costly penalties if supply is ever interrupted. That said, there is much to be hopeful about.

Another energy executive reckons that this could eventually lead to Venezuela exporting its onshore gas (currently being flared off and wasted) to Trinidad: improving efficiency and the environment. It could even lead to discussions on how we can help the refugees coming to TT, and seriously engage with Venezuela on human rights.

We are massively short of gas. It may sound strange, given that we export it and the world is awash with the good stuff. Gas is firstly used in Trinidad to generate power. Then, almost all the rest is liquefied and exported. What remains is used as “feedstock” for the plants in Point Lisas that produce chemicals that are exported, mainly for fertiliser. The energy producers have locked-in contracts that mean that almost all of our gas is exported.

When we were producing enough and earning tax dollars, this was a good deal. But our gas production has been in continual decline. There isn’t enough gas to satisfy local and external demand. Since the multinational energy companies make more money exporting gas than by selling it locally, this means that the plants in Point Lisas end up starved of gas. Some have shut down and sent home hundreds of workers. To help plug this shortage, and boost revenues, the government aims to pipe in gas from the Dragon field in Venezuela’s waters.

The celebration has been earned. But back to work. We won’t see first gas from the Dragon field until 2020. Moreover, as an energy executive pointed out, the gas is coming from Venezuela and will not be directly subject to our petroleum taxes – unlike gas produced from Trinidad waters. No doubt this is one of the reasons the energy companies are so keen to sign up. The Dragon field will also produce just 150 million cubic feet of gas per day, compared to our average current consumption of 3.46 billion cubic feet per day. And this is consumption with a number of mothballed plants. So, what can we do quickly?

It turns out that energy efficiency – once laughed at in a country with gas to burn – could be one additional way forward. Our lumbering power plants, partially owned and operated by multinational corporations, are ripe for investments in efficiency – and the operators have said so themselves. Powergen alone could save up to US$45 million a year in gas if it invested US$80 million to make their plant more efficient. This is according to both the National Gas Company (NGC), and youth-led non-profit IAmMovement’s co-founder Jonathan Barcant. This gas could be freed up for our chemical industry – allowing it to bring back workers. The numbers get even more impressive if renewable energy or LED bulbs are considered as gas saving alternatives.

With numbers like that, why haven’t they done it already?

The answer lies in the incentives embedded in the power-purchase agreements signed between the TT Electricity Commission (TTEC), the government and the international power operators. TTEC pays the generators by capacity (the amount of electricity they are able to produce) instead of by the amount of electricity they actually produce.

At the same time, TTEC guarantees and pays for the gas supply to the power plants. And in practice, TTEC hasn’t actually paid for any of the gas it receives from NGC.

So Powergen doesn’t benefit by investing in more efficient plants, even though the country as a whole would save money.

If an agreement was signed that allowed Powergen to benefit from investments in energy efficiency: this would be a win-win. Powergen would boost its bottom line, have a better operating plant, and (yes) reduce polluting carbon emissions.

Gas would be freed up for the downstream chemical plants, and NGC would benefit by finally getting paid. Most of all, the workers and engineers worried in their houses in Couva and Freeport could breathe just a little easier.

Kiran Mathur Mohammed is a social entrepreneur, economist and businessman. He is a former banker, and a graduate of the University of Edinburgh.


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.”


Dragon Gas Deal May Be ‘Political Gimmicks’

(Trinidad and Tobago Newsday, Richardson Dhalai, 26.Aug.2018) — The Dragon gas deal may be “public relations and political gimmicks” which may not benefit TT.

That’s the view of Pointe-a-Pierre MP David Lee who, in a media release yesterday, cited the 2016 trade deal between TT and Venezuela saying some local manufacturers had not yet been paid for goods which had been delivered to the South American nation.

On Saturday, Prime Minister Dr Keith Rowley and Venezuela’s President Nicolas Maduro shook hands to seal the deal that will see TT for the first time processing Venezuelan natural gas.

However Lee, in his statement, said recent public statements by the TTMA have indicated that “some manufacturers have not yet been paid for goods delivered to Venezuela which formed part of a trade deal fostered between the governments of our nation and Venezuela in 2016.”

He said this is not only proof of government’s “failed commitment” to the manufacturing sector but also “signs of a government which continues to abandon its responsibility of protecting our nation’s economic framework.”

“We in the Opposition were always concerned with this agreement given the economic hardship being experienced by the Venezuelan Government as well as this Government’s track-record of incompetence.” Lee said several questions had been directed to the Trade and Industry Minister Paula Gopee- Scoon in the Parliament but she had “on each occasion would respond by saying that some payments were still being received for shipped goods.”

“It is therefore unacceptable and irresponsible that over one year since these questions were first posed and over two years since goods were first shipped to Venezuela manufacturers have not been adequately compensated.”

He said the trade deal was a “government to government initiative” and questions have to be asked why the minister failed to take a trade delegation to Venezuela to address the issue.

“Did Government, knowing that Venezuela would not be able to keep its financial commitment just use our manufacturers as a bargaining tool to gain access to Venezuelan natural gas? They called the Opposition Members unpatriotic when we questioned these deals however the issues presently surrounding these non-payments demonstrate why the Opposition did so. Therefore our nation must remain vigilante and find no comfort in the signing of the Dragon Gas Deal which took place yesterday in Venezuela as this could be all about Public relations and political gimmicks as was seen with this trade deal.”


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.


Golar Power Affiliate CELSE Closes $1.3 Bln Financing

(Golar LNG, 25.Aug.2018) — Golar Power Limited’s affiliate, CELSE, closed a $1.34 billion financing facility for the Sergipe project.

On April 19, CELSE, the 50% Golar Power owned project company responsible for delivering the Sergipe I power project, executed a $1.34 billion non-recourse project finance facility. Excluding the FSRU facility, proceeds will fund remaining interest costs and capital expenditures for the project. Equity contributions from CELSE’s controlling partners, including Golar Power, have also been fully paid in. Assuming no dispatch under the Power Purchase Agreements, forecast annual EBITDA (1) from the power project (of which Golar is entitled to a 25% interest which will be reported as “equity in net earnings of affiliates” in the consolidated statements of income) including inflation uplifts to date is BRL 1.16 billion, equivalent to approximately $306 million at a USD/BRL rate of 3.8. Payments under the executed PPA are inflation indexed over the 25-year term and provide for pass-through of fuel costs when the power plant is called upon to dispatch. Around 94% of the project finance facility is also BRL denominated. This reduces net debt to $1.21 billion at the same USD/BRL rate, thus creating a natural hedge for currency movements.

The project, 66% complete by the end of July, is on schedule to commence operations on January 1, 2020. In excess of 2,000 workers are currently on site which is operating 24/7. Prefabricated GE modules, including generators and boilers, are being installed, transmission lines and pylons are being erected and the pipeline connecting the power station to the FSRU mooring is currently being laid.

Additional to the forecast annual EBITDA from the power project, the FSRU is expected to generate annual US CPI adjusted EBITDA of approximately US$41.0 million (of which Golar is entitled to a 50% interest which will be reported as “equity in net earnings of affiliates” in the consolidated statements of income). A financing commitment for the FSRU Nanook, due to deliver from the yard shortly, has been received and documentation is in its final stages. Net of the final FSRU delivery installment, the facility is expected to release approximately $70 million of cash to Golar Power.

The FSRU Nanook will, when it commences operations in 2019, represent the only entry point for LNG into Brazil outside Petrobras. Access to significant spare FSRU capacity could facilitate the supply of gas directly into the Brazilian grid as well as support a distribution hub for small scale distribution of LNG. The Company sees a number of very attractive opportunities to substitute expensive fuel based energy demand with cheaper and more environmentally friendly LNG solutions. The initial focus will be to target diesel to LNG conversions in the trucking industry as well as tailor-made LNG logistics solutions for the large mining and industrial market. Based on existing infrastructure in Sergipe, Golar Power is also well placed to participate in future Brazilian power auctions, with a clear competitive edge given that capital expenditure linked to the FSRU and grid connection has been substantially covered by the first phase of the project.

Note (1) on EBITDA: EBITDA is a non-GAAP measure. EBITDA is defined as operating income before interest, tax, depreciation and amortization. EBITDA is a non-GAAP financial measure. A non-GAAP financial measure is generally defined by the Securities and Exchange Commission as one that purports to measure historical or future financial performance, financial position or cash flows, but excludes or includes amounts that would not be so adjusted in the most comparable U.S. GAAP measure.


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.


Golar Applies for FSRU Permits in Brazil

(TO&GY, 24.Aug.2018) — Offshore midstream company Golar LNG has started the process to acquire an environmental permit for its Terminal Gas Sul (TGS) project in the Brazilian state of Santa Catarina, international media reported Thursday.

The project, which entails a new pipeline and FSRU capable of storing 160,000 cubic metres (5.65 mcf) of gas and regasifying 15 mcm (530 mcf) of LNG per day in Babitonga Bay, aims to supplement or even replace gas flowing into southern Brazil from Bolivia.

According Golar’s environmental permit application, the unit would likely receive around two LNG cargoes per month. Gas would move from the FSRU through a 2-kilometre subsea pipeline connected to a 31-kilometre pipeline onshore.

The company expects to receive the project permit in 2018 and approval from Brazil’s National Agency of Petroleum, Natural Gas and Biofuels in 2019. Project construction is scheduled to start in Q3 2019, with the unit coming on line in Q2 2021


U.S. Co. Wins Contract for Mexico LNG Project

(Natural Gas Intelligence, Peter de Montmollin, 22.Aug.2018) — A U.S. company has secured a long-term contract to build a liquefied natural gas (LNG) import project on the southern tip of Mexico’s Baja California peninsula, a region isolated from the country’s main energy transmission systems.

New Fortress Energy (NFE) won a tender to develop, build and operate the facility in the port of Pichilingue in the state of Baja California Sur, the company said Wednesday. The port’s administrator, Administracion Portuaria Integral de Baja California Sur, awarded the contract in July.

The project sponsors offered few details, but said the facility would entail a 3.5 billion-peso investment ($184 million) and could start up in 2020. Pichilingue is located just north of La Paz, the state capital.

The terminal could introduce a natural gas supply to Baja California Sur for the first time, allowing power plants in the region to use the molecule in lieu of fuel oil. The state, which encompasses the lower half of the peninsula, now lacks gas infrastructure.

The Baja California Sur power systems are also isolated from the national power grid on the mainland, as well as the Baja California system on the northern half of the peninsula, which is interconnected with San Diego Gas and Electric Co.’s network in Southern California.

Mexican state power utility Comision Federal de Electricidad (CFE) last year announced plans to tender an 810-mile transmission line, including a subsea section through the Sea of Cortez, which would connect Baja California Sur to the national grid. The Mexican Energy Ministry (Sener) expects that project to come in-service by 2023.

At an event to announce the Pichilingue contract, state governor Carlos Mendoza Davis reportedly highlighted the earlier start date for the LNG project versus the interconnection planned by CFE.

“This is a project that will expand the horizons for our development” as a state, the governor said.

Baja California Sur consumed 2,622 GWh in 2017, according to the Sener. The state’s installed capacity was 1,019 MW by the end of last year. Sener forecasts Baja California Sur to add 316 MW of capacity by 2032, with most of those additions occurring between 2021 and 2023.

Because of its isolation and lack of fuel alternatives, Baja California Sur has some of the highest electricity prices in Mexico. In the wholesale power market, day-ahead prices at the state’s La Paz node averaged 3,588 pesos/MWh in July, versus 1,933 pesos/MWh at the Queretaro node in central Mexico and 1,777 pesos/MWh at the Reynosa node on the northeast border with Texas, according to calculations by NGI’s Mexico GPI.

Most of the state’s generation plants are thermoelectric. It is also home to one of Mexico’s first utility-scale solar park, the 39 MW Aura Solar 1 plant near La Paz, a project whose development was spurred in part by the region’s elevated power prices.

Two separate power grids serve Baja California Sur. The smaller Mulege system cuts through the northern half of the state, while the main BCS system is on the peninsula’s southern tip.

The Pichilingue LNG project is adjacent to the BCS grid. The facility would also be sited about 650 miles south of the idle 1 Bcf/d Energia Costa Azul import terminal in the port of Ensenada, near the border with California.

Costa Azul has not injected any gas into Mexico systems since mid-2016 in part because of  the natural gas production boom in the United States and growing LNG demand in Asia. The facility’s owner, the Mexico unit of Sempra Energy, is looking to convert Costa Azul into a liquefaction facility to send gas exports to Pacific markets.

Mexico’s two active LNG terminals are the 700 MMcf/d Altamira on the Gulf Coast and the 500 MMcf/d Manzanillo on the Pacific. Altamira injected 309 MMcf/d in May, while Manzanillo supplied 500 MMcf/d.

Pichilingue would thus be Mexico’s fourth LNG import facility. Authorities have also announced plans to install a floating storage regasification unit (FSRU) in the port of Pajaritos in the southeast, along the Gulf Coast, although the project lost one of its two anchor customers earlier this year.

The new LNG projects at Pichilingue and Pajaritos would both serve areas with limited or no gas supply. Overall, Mexican demand for LNG is expected to diminish as pipeline infrastructure connected to the Permian Basin in Texas and other U.S. basins comes in-service later this year

Outside of Mexico, New Fortress has developed an LNG project in Jamaica to supply the 120 MW Bogue power station, via an FSRU charted from Golar LNG Ltd. It has also signed a contract with the Caribbean country’s power utility for another LNG project to fuel the planned 190 MW Old Harbour combined-cycle plant.

NEF is controlled by New York-based investment management firm Fortress Investments Group LLC.


New Fortress to Build $184 Mln LNG Terminal in BCS

(MexicoNow, 20.Aug.2018) – U.S. energy infrastructure developer New Fortress Energy (NFE) announced that it was awarded a long-term contract for the development, construction and operation of a terminal dedicated to the import of liquefied natural gas (LNG) in the port of Pichilingue, Baja California Sur.

This contract was the result of offering the best proposal in the public tender carried out by the Port Authority of Baja California Sur (APIBCS), which awarded the project to NFE on July 19. The project will represent private investment of $184 million could start up in 2020.

The terminal will introduce a natural gas supply to Baja California Sur for the first time, allowing power plants to lower the energy cost by up to 30%, which will greatly benefit the hotel sector, one of the main industries of the state.


Panama, US To Sign Pact To Expand Access To LNG

(Reuters, David Lawder, 17.Aug.2018) – Panama on Friday will sign an agreement with the U.S. Treasury and Energy departments aimed at paving the way for more private investment to expand the importation and distribution of U.S. liquefied natural gas in Latin America.

David Malpass, Treasury undersecretary for international affairs, said he hopes the “framework agreement” is the first of several with countries in the region to encourage investment to increase access to cheaper, cleaner energy.

The agreement is part of a Treasury-led initiative called America Crece, incorporating the Spanish word for growth, aimed at boosting U.S. LNG exports, developing Latin American energy resources and downstream demand.

Malpass is in Panama for the signing and the inauguration of a major new LNG terminal and 381-megawatt gas-fired power plant in Colon, Panama, run by U.S. power company AES Corp.

He said in an interview that new investments encouraged by the agreement will help turn the AES Colon project into an LNG distribution hub, with cargoes imported from the United States sent to other countries in the region, including Guatemala, Honduras, Nicaragua.

These countries and many Caribbean islands now rely largely on oil to generate electricity, with Venezuela a major supplier.

In 2017, French utility Engie and AES established a joint venture to market and sell LNG to third parties in Central America using the Panama terminal as a distribution hub.

The $1.15 billion AES facility on Panama’s Caribbean coast, which is expected to begin commercial generating operations on Sept 1, and LNG tank distribution operations in 2019, took in its first U.S. LNG cargo in June.

The Panama agreement allows for the U.S. agencies to help address regulatory and other barriers to investment, Malpass said, which can create opportunities for downstream demand and distribution.

“The framework agreement itself squarely addresses the obstacles that the private sector may be finding in that country,” Malpass said. In the case of Panama, he added, the framework agreement with the United States is a signal from Panama to the world that it welcomes investment, in particular private sector funding of projects.

The agreement also aims to encourage increased electrical grid access in rural areas of Panama and Central America and adoption of new technologies such as battery storage to improve reliability and foster economic development, he said.

(Reporting by David Lawder; Editing by Steve Orlofsky)


Sempra Energy Forms North American Infrastructure Group

(Sempra Energy, 8.Aug.2018) – Sempra Energy formed a new operating group for its North American infrastructure businesses and named Carlos Ruiz Sacristán chairman and CEO of the group, Sempra North American Infrastructure. Ruiz has served as chairman and CEO of Sempra Energy’s Mexican operating subsidiary, Infraestructura Energética Nova, S.A.B. de C.V. (IEnova) (BMV: IENOVA) since 2012.

Ruiz and the new Sempra North American Infrastructure group will report to Joseph A. Householder, president and chief operating officer of Sempra Energy. The group will encompass Sempra Energy’s Mexican operations contained within IEnova, Sempra LNG & Midstream’s existing operations, including Cameron LNG and all other liquefied natural gas (LNG) development and marketing activities.

As part of his new role, Ruiz will continue to serve as executive chairman of the board of directors of IEnova.

“Carlos Ruiz has overseen exceptional growth at IEnova, including its successful initial public offering in Mexico in 2013,” said Jeffrey W. Martin, CEO of Sempra Energy. “This new streamlined organizational structure will better align our non-utility operations to serve our global customers, and develop and execute projects even more effectively.”

“I’m honored and excited to serve in this new role at Sempra Energy and to continue my close involvement with IEnova,” said Ruiz. “We’ve built a strong and deep leadership team at IEnova and I will be devoting my full attention to growing Sempra Energy’s North American infrastructure business.”

Previously, Ruiz was a member of Sempra Energy’s board of directors from 2007 to 2012, when he became chairman and CEO of IEnova. Ruiz served as Mexico’s Secretary of Communications and Transportation during the administration of Dr. Ernesto Zedillo Ponce de León from 1994 to 2000. Previously he served in various positions at the Central Bank (Banco de Mexico) from 1974 to 1988, the Ministry of Finance from 1988 to 1992, and Petróleos Mexicanos in 1994. He currently is a member of the board of directors of Southern Copper Corp, Banco Ve por Más, S.A de C.V., Grupo Creatica, S.A. de C.V., member of the Technical Committee of Diego Rivera and Frida Kahlo Museum and a member of the Technical Committee Trust of Museo Nacional de Energía y Tecnología.

Ruiz, 68, holds a bachelor’s degree in business administration from Anahuac University in Mexico City and a master’s degree in business administration from Northwestern University in Chicago.

Tania Ortiz Mena, 48, will succeed Ruiz as CEO of IEnova, effective Sept. 1. Ortiz will report to Ruiz and will be nominated to serve on IEnova’s board of directors. Ortiz has served as IEnova’s chief development officer since 2014 and has held a range of leadership positions with IEnova since joining the company in 2000, including vice president for business development and external affairs, vice president of external affairs and director for government and regulatory affairs. Previously, Ortiz worked for PMI, Pemex’s international trading subsidiary.

Ortiz is a board member of Oncor Electric Delivery Co. and the Mexican Natural Gas Association, as well as vice president of the board for the World Energy Council – Mexico Chapter, member of the Energy Regulatory Commission Advisory Board and member of the Mexican Council for International Relations.

Octávio M. Simões, 59, currently president of Sempra LNG & Midstream, has been promoted to president and CEO of that company, reporting to Ruiz. Simões and his team will focus on maximizing the value of the company’s LNG opportunities. Simões also will continue in his role as chairman of Cameron LNG, LLC., the joint venture of which Sempra owns 50 percent. He has served as president of Sempra LNG & Midstream since 2012. Previously he was vice president of commercial development for Sempra LNG, where he was responsible for marketing the capacity of LNG receipt terminals, developing LNG facilities, securing LNG supply, securing shipping and acquiring equity positions in liquefaction plants. Prior to that, Simões served as vice president of asset management and vice president of planning and analysis for Sempra Generation, and in senior positions with Earth Tech and NEERI.

Justin C. Bird, 47, currently vice president of gas infrastructure and special counsel for Sempra Energy, has been named chief development officer for the Sempra North American Infrastructure group. In his new role reporting to Ruiz, Bird will be responsible for activities related to project development for all current and future LNG and midstream projects.

Amy Chiu, 52, vice president of asset management for Sempra LNG & Midstream, has been named chief asset management officer for the Sempra North American Infrastructure group. In her new role, Chiu will oversee Cameron LNG joint-venture management, Energía Costa Azul joint-venture management and LNG operations.

Kathryn J. Collier, 50, vice president and treasurer for Sempra Energy, has been appointed chief financial officer and chief administrative officer for the Sempra North American Infrastructure group. In her new role, she will oversee accounting, economic and financial modeling, human resources, information technology and procurement for the new operating group.

All of the organizational changes described above are effective Aug. 25, unless noted otherwise.


10MW LNG Power Plant for The Nest

(Jamaica Gleaner, Steven Jackson, 27.Jul.2018) – A tripartite deal is in the works for the development of a power plant at CB Group’s expansive property and future home called The Nest, that is meant to supply all the poultry company’s energy needs.

The disclosures so far indicate that Jamaica Public Service Company Limited, JPS, will develop and own the 10MW power plant that will be fuelled by liquefied natural gas (LNG), while New Fortress Energy will develop the LNG infrastructure and supply gas for the plant.

The energy project is referenced in a newly released environmental study on the proposed development of The Nest at Hill Run, St Catherine, which was published on planning authority NEPA’s website.

CB’s Corporate Affairs Manager, Dr Keith Amiel, said the power plant would make The Nest self-sufficient. CB and most of its satellite and subsidiary operations are expected to move into The Nest in 18 months.

“Anything remaining would be sold back to power the grid,” Amiel said on Wednesday.

The financing of the project was not disclosed, but the EIA for The Nest makes clear that JPS and New Fortress would have to develop their own environmental study for the power project – suggesting that the bulk of the investment may be coming from those two entities.

New Fortress, which has developed and is developing LNG supply infrastructure for several corporate entities, including JPS, typically fully finances and owns the gas infrastructure for such projects.

“US-based NFE will deliver LNG to the JPS 10MW distributed generation facility, located at the CB Hill Run facility, in order to provide the fuel required to operate electric power-generation units,” said the EIA report for The Nest. “NFE will provide all the infrastructure required to complete the LNG system and the distribution of natural gas project successfully, including storage tanks and regas/processing system.”

The project will include two storage tanks of more than 18,000 gallons in size, but the exact specifications are to be determined. The facility would be designed to store gas for five days, but will accept daily deliveries of 19,000 gallons trucked from New Fortress’ Montego Bay facility.

“They estimate 17.8 truck deliveries per week,” the report noted.

The Financial Gleaner awaits JPS’ promised response on its plans to develop the power plant.

CB’s poultry-processing plant at The Nest is an energy-intensive operation designed to process roughly 100,000 birds per nine-hour shift.

Development of The Nest 100, which spans acres at Hill Run, will proceed in phases over seven years. CB Group is investing $15 billion in the facility.


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.


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.


JUTC Hopes to Burn $3b Fuel Bill with LNG

(Jamaica Gleaner, Avia Collinder, 20.Jul.2018) – The LNG gas station to be developed by New Energy Fortress will have the capacity to fuel 25 buses daily, or five times the number of buses designated for the pilot programme to be conducted with the Jamaica Urban Transit Company, JUTC.

New Fortress spokeswoman Verona Carter also said it’s estimated that the five JUTC buses would require 720 gallons of fuel daily.

“Phase one of the fuelling station – up to 25 buses – cost US$1.7 million,” said Carter. The station is to be established in Spanish Town, St Catherine.

JUTC is hunting savings on its fuel bill, which, according to preliminary figures, topped $2 billion in the past two years. JUTC is projecting an even bigger fuel expense this year, $3.7 billion, according to the Jamaica Public Bodies report.

“If the pilot is successful the intention is to add more buses, but at this time – before the start of the first phase – we are not in a position to say when the expansion will be and by how many buses,” said JUTC spokesman Cecil Thoms.

JUTC has 608 buses in its fleet, only 525 of which are operational.

The public bodies report forecasts a rise in the bus company’s annual revenue by less than five per cent to $5.32 billion at year ending March 2019. But its fuel bill is projected to rise by a much faster clip, 46 per cent, from $2.52 billion to $3.68 billion.

If the numbers hold, JUTC would end up spending 69 per cent of the bus fares it collects on its fuel bill alone. The fuel bill would also surpass the expected $3.33 billion of staff expenses, the latter of which has been one of the company’s main cost drivers.

The LNG pilot programme being financed by New Fortress is scheduled for early next year. Any decision by JUTC and the Government on whether to embrace LNG as fuel for buses would not impact the current fiscal period.


New Fortress Invests $400 Mln in Pilot Project

(Jamaica Observer, 15.Jul.2018) – New Fortress Energy announced on Friday a new partnership with Jamaica Urban Transit Company (JUTC) for the introduction of the first natural gas-powered buses in Jamaica, which will significantly reduce emissions, pollution, maintenance and fuel costs.

As part of the partnership with the Government of Jamaica, New Fortress Energy will fund the pilot project for the conversion of five buses operated by JUTC to run on clean-burning liquefied natural gas (LNG) by early 2019.

The pilot programme, which consists of five new LNG-powered buses and a fuelling station in Kingston, is estimated to cost close to $400 million.

The new buses will reduce emissions and pollution and are expected to operate more efficiently, furthering the Government’s efforts to achieve energy diversification for sustainable economic growth and better protect the environment.

“We’re delighted to partner with the Government of Jamaica to introduce clean, reliable and affordable natural gas to the public transportation sector,” said Wes Edens, founder and chairman of New Fortress Energy.

“This partnership will be a catalyst for the transportation industry to reduce harmful emissions and pollution by using cleaner fuels. Jamaica continues to set an example with transformative energy investments that help grow the economy and protect the environment.”

Meanwhile, Minister of Transport and Mining Bobby Montague said, “We look forward to the conclusion of this pilot, using LNG-powered buses. We are very encouraged and excited about this groundbreaking initiative that will greatly enhance our environment. The Government is committed to support, create and enable the implementation of this pilot project. We anxiously await the results, so that a proper technical review can be done and chart a new pathway.”

He further noted that New Fortress Energy is funding five new buses so that the results of the pilot programme are not skewed by other factors.

The buses will be deployed across the system, and the ministry, along with JUTC stakeholders will be looking at the results to assess the success and viability.

In agreeing with the Minister, Paul Abrahams, managing director for JUTC, said; “This is indeed a significant milestone for our transport system and importantly, for our environment. We are very excited about it and look forward to the results post-pilot.”

Known as one of the safest, non-polluting and non-toxic fuels, LNG is an odorless fuel that offers significant energy efficiencies and emission reductions over alternative fossil fuel sources. It is cooled to a liquid form at -260°F and stored at atmospheric pressure, making it safe to handle and transport across the world.

The introduction of LNG as a clean and safe alternative fuel source in Jamaica is expected to lower energy costs and reduce environmental impact.


Could Guyana’s Oil Fortunes Curse Country?

(Energy Analytics Institute, Pietro D. Pitts, 8.Jul.2018) – Recent success in Guyana’s oil sector could be a wolf in sheep’s clothing.

Guyana doesn’t yet produce oil but in coming years its oil output is expected to surpass that of Peru and Trinidad and Tobago and could approach that of Ecuador, one of two lone OPEC producing countries in South America.

Having the world’s largest oil reserves, the first LNG export terminal in the Americas, or large gas reserves doesn’t mean all a country’s political, economic and social problems will be solved. Just ask Venezuela, Trinidad and Tobago, and Bolivia, respectively. Case studies of these three countries have shown that not just countries in Africa, such as Nigeria, are vulnerable to the Dutch Disease even in the 21st Century.

A look just at Guyana’s poor Corruption Perceptions Index ranking from Transparency International, much lower than the average for the Americas indicates the government is failing in efforts to tackle corruption.

It is hardly likely that Guyana’s faith will change by 2020 when the oil starts flowing and revenues start to climb. What will happen then is almost predictable unless a miracle happens between now and then.


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.


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.


Enbridge Begins U.S.-Mexico Portion of Valley Pipeline

(Reuters, 13.Jun.2018) – Canadian energy company Enbridge Inc. said it started construction of the offshore border crossing section of its US$1.6-billion Valley Crossing natural gas pipeline between Texas and Mexico, according to a federal filing made available on Wednesday.

The company said in an e-mail the pipeline remains on track to enter service in October.

The latest filing pertains to a 1000-foot (305-meter) section of offshore pipe that extends to the U.S.-Mexico border. The remaining 165 miles of onshore and offshore pipe has been completed and commissioning activities will commence in the near future, Enbridge spokesman Devin Hotzel said in an e-mail.

The Valley Crossing project is designed to carry up to 2.6 billion cubic feet per day (bcfd) of gas from Texas to help Mexico meet its growing power needs as generators there shift away from fuel oil and imported liquefied natural gas.

One billion cubic feet is enough to fuel about five million U.S. homes for a day.

The Valley Crossing project has been under construction since April, 2017, according to the Enbridge website. In May, Enbridge said it had “substantially completed” the onshore part of the pipe and was working on the offshore part to meet a fourth-quarter 2018 in-service date.

Valley Crossing will connect in the Gulf of Mexico to the Sur de Texas-Tuxpan pipeline under construction by a joint venture between units of TransCanada Corp. and Sempra Energy. Once complete, it will be the biggest gas pipe between the two countries.

There are already about 20 pipelines that can move gas from the United States to Mexico with a total capacity of around 10.9 bcfd, according to U.S. energy data. That includes Howard Energy’s 0.6-bcfd Impulsora pipeline, which is expected to enter service this month.

Analysts have said, however, that constraints on the Mexican side of the border have so far limited a big increase in U.S. pipeline exports.

Since the start of the year, U.S. exports to Mexico have averaged 4.0 bcfd, up just a bit from the 3.9-bcfd average during the same period in 2017, according to Thomson Reuters data.

While the pipeline constraints remain, Mexican energy companies have been buying more U.S. liquefied natural gas (LNG) than any other country since February, 2016, when the first U.S. LNG export terminal opened in the lower 48 states at Cheniere Energy Inc.’s Sabine Pass in Louisiana.

Mexico bought 50 cargoes of LNG totalling 167.8 billion cubic feet of gas from the United States, 18.8 per cent of total U.S. LNG exports between February, 2016, through the end of 2017.

Total, Siemens Hope to Sign Cuban LNG Deal Soon

(Reuters, Marc Frank, 30.Apr.2018) — French energy firm Total SA and German industrial giant Siemens AG hope to sign a deal soon with Cuba to build a 600 megawatt gas-fired power plant on the island, according to diplomats and businessmen with knowledge of the talks.
The two are leading a consortium that has been in negotiations with Communist-run Cuba since last year when they won a tender for the project, said the sources, who did not identify the other members
“Total, with some international partners, is looking at a LNG power project in Cuba, one of several countries where Total is exploring similar LNG potentials,” the company said in a statement to Reuters.
A Siemens spokesman in Germany was not immediately available for comment.
The sources cautioned that many details of the project were under negotiation and that the combination of U.S. sanctions and Cuban bureaucracy meant there was no guarantee the agreement would be finalized, though they were hopeful.
The potential deal is the latest example of companies from the European Union moving to take advantage of Cuba opening to foreign investment.
“The EU has become Cuba’s first trade partner and was already the first in investment and development cooperation,” the European Union’s top diplomat Federica Mogherini said in January while visiting the country.
Siemens signed a letter of intent with the Cuban power authority in 2016 to help modernize the grid.
“With this important agreement … we will assist and support Cuba on the development of a sustainable and modern electricity system,” Willi Meixner, head of Siemens Power and Gas division, said at the time.
In the Matanzas Bay project, 124 kilometers (77 miles) east of Havana, Total would obtain the liquid gas from abroad, and then store, process and supply it to the plant, which would be built by Siemens, the sources said.
The project would mean less dependence on oil and less pollution, Jorge Pinon, a Cuban energy expert at the University of Texas in Austin, said.
“It could be the best decision that the Cuban government has made toward an energy policy able to react to changes in price, geopolitical events and or supply-demand disruptions,” he said.
Cuba was left in the lurch when its sole oil supplier, the Soviet Union, collapsed in 1991. More recently it has been scrambling to find alternative oil supplies as ally Venezuela’s economy and oil production implode.
Cuba’s total generating capacity is around 6,000 megawatts and demand is increasing due to growing tourism, digitalization and a new private sector.
Around 95 percent of electricity in Cuba is generated by fossil fuels. The government has begun a program to generate 24 percent with renewable sources by 2030.
Total and Siemens have engaged in commerce with the Caribbean island nation for decades.
Total was the first foreign company to drill for oil just off shore in the 1990s after the Soviet Union collapsed. The company failed to find a commercially viable field.
It also has a joint venture with Cuban state oil monopoly Cubapetroleo (CUPET), Elf Gas Cuba, which for 20 years has packed a liquid propane and butane gas mix into cylinders and distributes them for use by households and businesses in eastern Cuba.
The Cuban state power authority, Union Electrica, and CUPET did not respond to a request for comment. (Reporting by Marc Frank Editing by Daniel Flynn and Susan Thomas)

Bolivia Looks to Build Gas Liquefaction Plant in Ilo

(Energy Analytics Institute, Jared Yamin, 5.May.2018) – Bolivia plans to construct a gas liquefaction plant in the Peruvian port of Ilo in order to consolidate LNG exports.

The decision, announced by Bolivia’s Hydrocarbon Minister Luis Alberto Sánchez, was made without taking into account certified natural gas reserves or decline rates at the giant Tarija field, reported the daily El Diario.

CFE Cancels Baja California Sur Natural Gas Project

(Platts, 30.Jun.2017) — Mexican state-run utility CFE has canceled its auction to bring natural gas into the Pacific state of Baja California Sur, the company said.

CFE said the gas project isn’t necessary as its new underwater transmission line project will fulfill the electricity needs of the state.

“By opting for this alternative to strengthen the reliability of the Baja California Sur electrical system, CFE will no longer continue with the auction for the provision of natural gas transportation to the entity,” it said in a statement Thursday.

The $600 million natural gas project would have provided up to 227 MMcf/d of fuel to transform CFE’s fuel oil generation fleet in Baja California Sur, according to CFE’s auction documents.

The $1 billion underwater transmission line will cross the Sea of Cortez, connecting Bahia de Kino, Sonora, and Infernito, Baja California Sur, according to Mexico’s Energy Secretariat (SENER) National Electric System Development Program (PRODESEN) 2017-2031.

The transmission line is expected to be operational by 2022, and it will connect the state with the rest of the country for the first time through a 105-km, 400 kV underwater direct transmission cable.

The underwater transmission line will connect the state with CFE’s growing combined-cycle natural gas plant fleet in the states of Sonora and Sinaloa, thus displacing expensive diesel- and fuel oil-generated power in Baja California Sur.

In Topolobampo, Sinaloa, CFE awarded Spain’s Iberdrola the construction of the 778-MW Topolobampo II and 777-MW Topolobampo III combined cycle plants. Both will be operational in 2019 and 2020.

CFE said the project would provide “highly competitive electricity prices” to Baja California Sur’s 40,000 users, which receive the most electricity subsidies in the country, while cutting emissions from fuel oil and diesel generation in the state.

PRODESEN showed that Baja California Sur has 976 MW of fuel oil- and diesel-fueled generation, of which 418 MW is internal combustion engines, by far the largest amount in any Mexican state.

Jose Luis Leyva, CFE’s communications director, told S&P Global Platts on Friday that Baja California Sur’s existing diesel and fuel oil capacity will still be used by CFE for backup and peak generation.

The construction of the underwater transmission line will help to increase the integration of more renewable capacity in Baja California Sur, CFE said in the statement.

According to PRODESEN, 423 MW of renewable energy capacity will be built in the state over the next 15 years, 312 MW of which will be 12 solar photovoltaic projects.

–Daniel Rodriguez, newsdesk@spglobal.com

–Edited by Annie Siebert, ann.siebert@spglobal.com


AES Terminal to Supply Caribbean, Central America

(AES Dominicana, 28.Jan.2017) – The AES Dominicana Liquefied Natural Gas reception terminal, located in the AES Andres energy complex, has completed the modifications to allow for re-loading and re-exportation of LNG to neighboring Caribbean islands and Central American countries, which can now benefit from the environmental and economic advantages of natural gas.

The information was provided by George Nemeth, Director of LNG Business Development at AES Mexico, Central America and the Caribbean (MCAC) during the 17th Annual Conference on Energy in the Caribbean organized by the Platts international institute, held in the Dominican Republic from January 26 to 27.

According to Nemeth, nine million dollars were invested in the project to build the new installations of the “AES Andres Marine Facility,” which consisted in adapting the existing LNG Reception Terminal to be a port of entry and exit for ships as small as 10,000 cubic meters, which can be filled directly from the existing LNG receiving terminal jetty. For smaller customers, AES will load LNG into ISO tanks at the Liquefied Natural Gas Truck Terminal so that LNG can be delivered via container vessels to neighboring countries. AES has recently begun exporting LNG to the Caribbean via ISO containers.

Innovative project

“This is a highly innovative project that counts on all the guarantees of safety and reliability in addition to the experience that all our professionals have in AES Dominicana that for more than 13 years have successfully operated the LNG terminal and during seven years the terminal to fill trucks,” said AES Dominicana President Edwin De los Santos.

With this project, which concluded at yearend 2016 – De los Santos says – Dominican Republic takes advantage of its excellent geographical location and becomes the first hub of Central America and the Caribbean for the import and export of natural gas, which translates into advantages of being an environmentally-friendly non-renewable energy, it’s clean because it doesn’t spew ash when ignited, it’s non-toxic and produces lower emissions than the traditional naphtha and diesel.

2017 and a vision of clean energy and innovation.

The commissioning of the AES Andres Marine Facility is one of the projects AES Dominicana has in its portfolio and joins the large-scale battery energy storage array system at AES Andres, Itabo and DPP, first and only in the Dominican Republic and the Central American and Caribbean region, which consists of installing around 30 megawatts (MW) to contribute to the stability of the interconnected electrical system (SENI) and continue with the injection of more efficient energy into the system. The DPP combined cycle will also start operations, which will inject an additional 114 MW of clean energy.

As to renewable energy, AES will add an average of 3.5 MW, through two solar projects in AES Andres and Itabo and two projects of micro hydraulic turbines, to maximize the injection of clean energy into the SENI.


Enargas Mandates Complexes To Reduce Gas Demand

(Energy Analytics Institute, Jared Yamin, 1.Jun.2016) – Union protests in Tierra del Fuego as well as climatic conditions have made it impossible to bring in LNG ships into the Buenos Aires province; thus, forcing the Argentina government to take steps to reduce demand for gas.

An emergency committee meeting proposed by Enargas concluded the only alternative was to order major productive complexes to reduce consumption of the resources to zero, reported the daily newspaper La Nacion.


Enarsa to Import Gas From Chile

(Energy Analytics Institute, Jared Yamin, 23.May.2016) – Argentina’s state oil company Enarsa signed a contract to purchase natural gas from Chile at a price 53 percent higher than the LNG that arrives to Chile on tankers and 128 percent higher than what is pays for imports from Bolivia, reported the daily El Diario.

“Bolivia sends gas to Brazil and Argentina but does not have any more,” reported the daily La Razón, citing Energy Minister Juan José Aranguren. “Today, Argentina imports gas from Bolivia at $3/MMbtu, but will import gas from Chile at $7/MMbtu.”

The purchase of gas from Chile at $7/MMbtu will allow Argentina to save $46 million through the displacement of gasoil that it would have to buy at $10/MMbtu to generate electricity, said the minister.

Argentina will commence importing gas from Chile using the same gas pipelines that it used until 2006 to export gas to Chile, reported La Razón.

“We are replacing a product that costs us $10/MMbtu with another that costs us $7/MMbtu,” said Aranguren. “Obviously it is more than $3/MMbtu but there is not enough (Bolivian) gas.”


Argentina Interested in Buying Excess Gas from Punta De Sayago

(Energy Analytics Institute, Aaron Simonsky, 11.May.2016) – The government of Uruguay continues to move forward with agreements to secure markets for natural gas to come from its proposed regasification plant in Punta de Sayago.

Uruguay’s President Tabaré Vázquez and Industry, Energy and Mining Minister Carolina Cosse, signed a decree that will authorize the approval of a pre-agreement between Uruguay and Argentina for the purchase-and-sale of natural gas produced in Uruguay, reported the daily newspaper LaRed21.

In recent months officials from Argentina have continued to reiterated the country’s interest in acquiring gas from its neighbor Uruguay.

An Interconnection Commission will be formed within 30 days once the countries finally reach an agreement.

The time frame for the purchase of the gas will be 10 years after the regasification plant starts operations.

“It is estimated to start working in the second half of 2017, if Uruguay decides to realize the investment,” reported the daily, citing Cosse.


Rosneft to Partner with PDVSA in Mariscal Sucre

(Energy Analytics Institute, Piero Stewart, 1.Apr.2016) – Russia’s Rosneft OAO and PDVSA signed an agreement for joint development of production, treatment and the sale of natural gas from the Mariscal Sucre project offshore.

Rosneft and PDVSA will each hold a 50 percent interest in the venture which includes the fields Patao, Mejillones and potentially Rio Caribe, according to the Rosneft statement.

The three fields comprise part of the Mariscal Sucre natural gas project off the eastern coast of Venezuela. Another offshore field, Dragon, is also part of Mariscal Sucre but apparently not covered by the agreement. Activities at the Mariscal Sucre project are just 20 percent complete, announced PDVSA, as the Caracas-based company is known, in a statement on its website.

Rosneft has announced production from the three fields could potentially reach 25 million cubic meters (883 million cubic feet) per day, which could be shipped by pipeline or as liquefied natural gas, also known as LNG.


GenPower, ExxonMobil Sign Framework for LNG Supply

(Golar LNG, 4.Mar.2016) — Golar GenPower Brasil Participações S.A., a joint venture between LNG Power Limited (UK), a standalone non-recourse subsidiary of Golar LNG Limited and GenPower Participações S.A., announced that it has signed a framework agreement for the supply of LNG to the natural gas fired power generation project it is developing in the Brazilian state of Sergipe.

Golar GenPower and ExxonMobil Titan LNG Limited have agreed heads of terms covering the supply of LNG to the approximately 1,500MW Porto de Sergipe project. The agreement also establishes a framework for LNG to be supplied exclusively from ExxonMobil for expansion phases and other projects that Golar GenPower is pursuing in Brazil. The LNG supply is conditional on execution of a fully termed LNG Sale and Purchase Agreement (SPA). Golar GenPower intends to bid at the upcoming 2016 Leilao A-5 Power Auction.

This framework agreement is a significant step towards a positive final investment decision on the Porto de Sergipe project which Golar GenPower hope will be the first of several Brazilian opportunities jointly delivered over the coming years.


AES Awarded Panama’s First Gas-Fired Plant

(AES Corporation, 11.Sep.2015) – AES Corporation announced that its subsidiary, Gas Natural Atlantico S. de R.L., won a competitive bid process conducted by the Electric Transmission Company, SA (ETESA), the state’s electric transmission company, to supply 350 MW of new capacity. The project will include the construction of a 350 MW combined cycle natural gas-fired plant with a 10-year Power Purchase Agreement (PPA), and a 170,000 m3 LNG storage tank and regasification facility, to supply gas to the plant, as well as to potentially serve growing demand for natural gas in Central America.

“Together with our local partner, Inversiones Bahia, we are very happy to announce that we were the lowest bidder for ETESA’s 10-year PPA for 350 MW. We will construct a low emission combined cycle power plant, which will be fueled by LNG via the new regasification terminal on Panama’s Atlantic coast,” said Andrés Gluski, AES President and CEO.

“Building a state of the art LNG regasification terminal near the entrance of the enlarged Panama Canal will enable Panama to become an energy hub for Central America and the Caribbean, by supplying lower cost, reliable and sustainable fuel, which will benefit many sectors, including electricity generation, transportation and ship bunkering.”

AES expects to sign the 10-year PPA by YE:15. The project is subject to customary regulatory approvals including, but not limited to, an environmental impact assessment study and a definitive generation license. These approvals and financial close are expected before commencement of construction. Construction of the project is expected to begin in early 2016, with commercial operations expected in 2018. The total project cost is expected to be in the range of $800-$900 mln, which will be financed with a combination of non-recourse debt, equity from partners and AES equity of up to $210 mln.

AES entered Panama 16 years ago and since then has made a total investment of more than $1.3 bln in the country. Currently, AES owns 777 MW (471 MW on an ownership-adjusted basis) of mostly hydroelectric generation.


Venezuela Eyes Gas Exports, Floating LNG

(Energy Analytics Institute, 18.Jun.2015) – Petroleos de Venezuela SA (PDVSA) plans to boost investments in the Venezuelan natural gas sector over the next five years in order to almost double production to meet increasing domestic demand, reduce its reliance on fuel imports and eventually export excess gas volumes to generate additional dollar income.

PDVSA, as the state oil company is known, plans capital investments of $38.4 billion during 2015-2019 to increase natural gas production from 7.4 Bcf/d in 2014 to 10.5 Bcf/d by 2019, said PDVSA official Douglas Sosa on June 18, 2015 during a hydrocarbon congress in Maracaibo, Venezuela. Increased gas production will assist PDVSA met increasing demand in the domestic market and reduce its dependence on costly refined product imports. Excess gas production could be destined for export markets in Latin America as well as Trinidad.

“We are talking about exports to Trinidad, Central America, South America and if we consider the LNG projects that we are promoting we could export this gas to further destinations,” said Sosa.


T&T Energy Ministry Supports Expansion into Guyana

(Piero Stewart, Special for Energy Now, 1.Jun.2015) – Trinidad and Tobago will seek to capitalise on energy projects in the region as part of broader push outside of the country’s borders, and especially into Guyana, which has recently announced a significant offshore oil discovery.

Oil field service companies from Trinidad and Tobago are already dominant players in Suriname and will be interested in conducting work in Guyana, said Trinidad and Tobago Energy Minister Kevin Ramnarine during an interview June 13 in Port-of-Spain.

“There is a role, therefore, for us to have our energy service companies enter the Guyanese frontier energy economy, and this is something we support.”

Esso Exploration and Production Guyana Ltd., an affiliate of Irving, Texas-based ExxonMobil, announced in late May that the Liza-1 well it had drilled offshore Guyana in the Stabroek block had discovered more than 295 feet of oil pay.

Since the announcement, already-tense relations between the governments of Venezuela and Guyana flared up after the former redrew its maritime border to include the Stabroek discovery.

Earlier this year, Trinidad’s prime minister announced that the country would be be working with the IADB to form an Energy Fund that would help stakeholders to capitalise on energy projects in the region, and specifically those related to power and regasification, among other sectors.

“So that is going to be a major policy imperative for the next five years,” said Ramnarine.

Trinidad and Tobago, home to Atlantic LNG, the first LNG export facility in Latin America, is looking to expand its service and experience into the region.


LNG Projects Nixed Amid Low Oil

(Moody’s, 7.Apr.2015) – LNG suppliers are curtailing their capital budgets, amid low oil prices and a coming glut of new LNG supply from Australia and the U.S.A., Moody’s Investors Service said in its report, “Lower Oil Prices Cause Suppliers of Liquefied Natural Gas to Nix Projects.”

Moody’s says low LNG prices will result in the cancellation of the vast majority of the nearly 30 liquefaction projects currently proposed in the U.S.A., 18 in western Canada, and 4 in eastern Canada.