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.

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Venezuela Oil Sales to US Fell in August

(Reuters, 4.Sep.2018) — Venezuela’s crude sales to the United States fell in August for the second month in a row as exports of two of the South American country’s main grades dropped following port interruptions by a tanker collision, according to Thomson Reuters Trade Flows data.

Venezuela’s state-run oil company Petróleos de Venezuela, S.A., known as PDVSA, and its joint ventures last month exported an average of 468,300 barrels per day (bpd) of crude in 30 cargoes to their customers in the United States, the data show. The total was the third smallest monthly figure this year.

PDVSA’s oil shipments have been affected in recent weeks by export limitations at the country’s main oil port, Jose, after a minor tanker collision forced the state-run firm to halt operations at one of its three berths.

The Jose dock problem came as the country was attempting to reverse a series of blows to oil exports, including declining output, a severe lack of investment in its energy infrastructure and asset seizure attempts by creditors.

PDVSA last week started a contingency plan for diverting tankers waiting at Jose to load to the nearby terminal of Puerto la Cruz. It has not said for how long Jose’s loadings would be affected.

The state-run company last month exported to the United States a 500,000-barrel cargo of Merey crude and three 500,000-barrel cargoes of Zuata crude, two of the OPEC-nation’s main grades for exports. Both come from the Orinoco Belt, Venezuela’s largest oil producing region.

Crude upgraders at the Orinoco, essential for turning Venezuela’s extra heavy oil into exportable grades, have been working intermittently in recent months due to planned maintenance and outages, limiting volumes available for export.

U.S. refining firm Valero Energy was the largest receiver of Venezuelan crude last month with 153,000 bpd, followed by PDVSA’s unit Citgo Petroleum and Chevron Corp , according to the data.

Shipments to spot customers in the United States continued falling to some 40,000 bpd in August, the second smallest monthly figure so far this year.

(Reporting by Marianna Parraga; Editing by Richard Chang)

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Petro-Victory Purchases Assets in Brazil

(Petro-Victory Energy Corp., 4.Sep.2018) — Petro-Victory Energy Corp. announced a $1.6 million acquisition of production and working interests in 4 oil fields, comprised of 12,850 gross acres, located within three developed onshore basins in Brazil, and commits capital to materially expand production. The acquisition was financed using the company’s existing $10.0 million credit facility.

“These fields are located in mature, oil prone basins, with well understood geology and low geological risk. Reservoirs are of excellent quality and our hydrocarbon pay zones are at shallow depths (1-1.5km) allowing for low cost development drilling. The fields produce excellent quality light sweet crude with no impurities, meaning we can achieve a higher price for crude sold,” said Petro-Victory Chief Operating Officer Richard Lane.

Highlights

— $1.6 million acquisition cost ($125 per acre). $0.375 million paid at signing, $1.225 million paid upon Agencia Nacional do Petroleo Gas Natural e Biocombustiveis of Brazil (ANP) approval.

— Acquisition consists of:

– 100% operating interest in the Andorinha onshore producing oil field in the Potiguar Basin

– 100% operating interest in the Alto Alegre onshore oil field in the Potiguar Basin

– 50% non-operating interest in the Carapitanga producing onshore oil field in the Sergipe-Alagoas Basin

– 50% non-operating interest in the São João onshore oil field in the Barreirinhas Basin

— Existing infrastructure acquired includes 21 drilled wells, pipelines, power generation and electrical lines, pumping units, paved roads, storage tanks, 3D and 2D seismic with a combined estimated cost of > $50 million

— Seismic and well data will be used to construct a new development plan. Initial work has indicated significant upside opportunities.

— Potential for new wells to materially increase production. Management estimates the 4 fields have the potential to achieve >1,000 BOPD.

— Near term well recompletions estimated to increase net production to >100 BOPD

— Q2 2018 average production of 20 BOPD from four mature wells in the two producing fields, Andorinha and Carapitanga

— The company acquired the producing assets from Empresa de Engenharia de Petróleo Ltda. (ENGEPET) and has an operating partnership with ENGEPET to optimize field production for Carapitanga and Sao Joao fields.

— Transaction subject to approval from Agencia Nacional do Petroleo Gas Natural e Biocombustiveis of Brazil (ANP). The Acquisition has been conditionally approved by the TSX Venture Exchange (the TSXV) but is subject to final approval of the TSXV.

“This acquisition positions us in Brazil at a time when onshore oil and gas investment is poised for revitalization. The market opportunity in Brazil has become more attractive with improvements in the economy as well as a move higher in oil prices. We are excited as we leverage long-term relationships within Brazil that present opportunities that fit Petro-Victory’s growth and returns focused strategy. Our acquisition and expected capital costs will generate strong margins and cash flows,” Petro-Victory Chief Executive Officer Richard F. Gonzalez.

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Frontera Resumes Production in Peru at Block 192

(Frontera Energy, 4.Sep.2018) — Repairs have been completed on the NorPeruano pipeline in Peru and it has now resumed normal operations, allowing Frontera Energy Corporation to restart production from Block 192.

“We are pleased to see the resumption of service on the NorPeruano pipeline and the increase in production from Block 192 in Peru, a very important producing asset for Peru and for Frontera,” said Frontera Chief Executive Officer Richard Herbert.

On June 4, 2018, Petroperu S.A. declared force majeure on the NorPeruano pipeline, which transports crude oil from Block 192 to the export terminal at Bayovar. Prior to the force majeure event, the Block was producing approximately 8,600 bbl/d net to Frontera. Petroperu began repairing the pipeline in mid-June and the pipeline resumed operations on August 30, 2018.

With reactivation of the pipeline, Frontera has commenced pumping crude oil from storage and will ramp production back up to pre-force majeure levels in the coming days. While the pipeline was shut down, the company undertook a work-over and well service program which is expected to add additional daily volumes once the Block ramps up to full production. As of September 3, 2018, the gross production level rose to over 10,000 bbl/d and it is projected to be over 12,000 bbl/d in a few days.

“We look to continue operating the Block in an effective manner for the remaining life of the contract, now expected until September 2019,” said Herbert.

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OOS Drillship to Support Pemex Campaign

Photo: OOS Energy

(Offshore, 4.Sep.2018) — OOS Energy has won its first drilling contract offshore Mexico.

The OOS Tiger 1 drillship will support Marinsa & PPS (Pemex Drilling) for a 15-month program.

The vessel, built at Shanghai Shipyard in China, is a moored drillship capable of working in water depths up to 5,000 ft (1,524 m), and to drilling depths of up to 31,500 ft (9,601 m).

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How Will Guyana Deal With Its Oil Windfall?

(CNNMoney, Talib Visram, 4.Sep.2018) — The South American country with the smallest GDP is about to burst with oil.

ExxonMobil found oil off Guyana’s coast in 2015, and believes the reserves are big. Conservative estimates project to about 4 billion barrels. Some experts think there’s more to be found in the country’s 6.6 million-acre Stabroek Block.

But how Guyana prepares for the windfall from a newly discovered fossil fuel repository will have big ramifications for its future.

For a country with a population of fewer than 800,000 and a GDP of slightly more than $6 billion, the discovery is life changing.

“There’s a realistic chance of this transforming the economy,” said Pavel Molchanov, senior vice president and equity research associate at Raymond James. “It’s particularly impactful for a small country like Guyana.”

When the first oil starts to flow, which ExxonMobil hopes will be in 2020, Guyana could reap billions almost immediately.

By 2025, ExxonMobil wants to produce 750,000 barrels of oil per day.

History contains numerous cautionary tales about countries that have squandered a sudden surge of riches.

Venezuela struck oil centuries ago, but in 1998 the government of Hugo Chávez installed political loyalists into top jobs in the nationalized oil industry and began diverting the revenues into social programs. The country failed to reinvest into its oil infrastructure and when oil prices crashed, so did Venezuela’s economy. Now, even basic goods like food and medicine have to be imported. Hyperinflation is soaring and the IMF predicts it’ll hit a rate of 1,000,000% by the end of 2018.

Equatorial Guinea’s also squandered its oil windfall, but through wanton corruption. Between 2000 and 2013, the small West African nation brought in $45 billion of oil revenue. But it remained one of the poorest countries because the dictatorial government went on indulgent spending sprees in France.

Corruption, infrastructure and unexpected market forces could present challenges for Guyana, too.

The democratic republic comprises two political parties made up of descendants of African slaves on one side and descendants of Indian indentured servants on the other.

The fear is that the government in power could unfairly favor its ethnic constituents.

At the moment, the Afro-Guyanese party, the PNC, is running the government. But there’s an election in 2020, which could decide who controls the purse strings.

“I wouldn’t discount civil unrest, even for such a small country,” said Eileen Gavin, senior politics analyst at Verisk Maplecroft.

Guyana should also be aware of “Dutch disease,” a phenomenon in which existing industries are forgotten in favor of a new one. Guyana currently makes most of its revenue from exporting gold, bauxite, sugar and rice.

Some countries have handled windfalls well, and not spent everything at once. Notably, Norway set up an “oil fund” for investing surplus revenues to benefit future generations.

Most experts agree that Exxon’s contract with Guyana is favorable toward the oil giant. The IMF recently advised the Guyanese government to revise the contract for future deals, stating that its tax laws are “well below what is observed internationally.”

But some say that a contract in Exxon’s favor at this point is to be expected, given Guyana’s lack of experience and infrastructure for the extraction.

“Nothing had ever been found in Guyana before,” said Ruaraidh Montgomery, senior analyst at Wood Mackenzie. “So, it’s high risk in a frontier area. They needed to offer appealing fiscal terms to attract investors.”

And as the oil is tapped and more is found — and the investment risks disappear — Montgomery said Guyana, a “world-class hydrocarbon basin,” would probably tighten its future contracts.

For now, Guyana is doing everything right on paper in preparation, said Gavin. It’s due to establish a sovereign wealth fund this year, and has joined the EITI, an organization that helps countries “manage hydrocarbon reserves in a fiscally responsible manner.”

But it’s still too early to tell. “The proof of the pudding will be in 2020, when the revenue starts to flow,” Gavin said.

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