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[waldron] 06/4/2020 13:47

Natural Gas 06 Apr 2020 | 09:49 UTC Algiers

Algeria's Sonatrach hooks up new southwestern gas pipeline to grid

Author Illies Sahar with Stuart Elliott Editor Alisdair Bowles Commodity Natural Gas

Highlights

GR7 pipeline to link Hassi Mouina to Hass R'Mel hub

Extension of GR5 pipeline to Touat, Reggane, Timimoun

Priority to develop gas projects in Algeria's southwest

Algiers — Algeria's state-owned Sonatrach has completed the construction of a gas pipeline to link new fields in the southwest of the country with its main distribution hub at Hassi R'Mel, the company said at the weekend.
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The 4 Bcm/year capacity GR7 pipeline links the field complexes of Hassi Ba Hamou and Hassi Mouina to the Hassi R'Mel hub from where Algerian gas can be transported north for export to southern Europe.

The pipeline is an extension of the GR5 pipeline, which brings gas from the recently commissioned Touat, Reggane Nord and Timimoun gas fields to Hassi R'Mel.

"The new pipeline will allow the capacity of Sonatrach's system Reggane-Hassi R'Mel to reach some 13 Bcm/year," the company said.

The GR5 pipeline previously had a capacity of 9 Bcm/year.

New producing region

Developing new fields in the southwest of Algeria and linking them to the rest of the gas network has been a strategic priority for Sonatrach over the past few years.

Together with partner Neptune Energy, gas from the 4.7 Bcm/year Touat field was first fed into the Algerian network in September last year.

Before that, Sonatrach and partners Total and Cepsa began production from the 1.8 Bcm/year Timimoun field in February 2018, while the 2.8 Bcm/year Reggane Nord field began producing in December 2017.

Both the Hassi Ba Hamou and Hassi Mouina projects have faced significant delays, however.

Sonatrach had hoped to bring them online by 2018, but both are still several years from starting production

The Hassi Ba Hamou field complex will consist of three new gas treatment and compression installations, and is expected to produce at some 11 million cu m/d (4 Bcm/year).

The Hassi Mouina license in Adrar, southwestern Algeria, was won by Equinor in 2005 and several gas discoveries were made, but the company abandoned the project, and Sonatrach took it on alone.

According to the development plan, gas production could be 3.8 million cu m/d at Hassi Mouina North and 3.8 million cu m/d at Hassi Mouina South, for a total of 7.6 million cu m/d from the project -- the equivalent of 2.8 Bcm/year.

[grupo] 31/3/2020 11:25

Shell exits from Lake Charles LNG project in Louisiana, US

Oil & GasMidstreamLNG Terminal

By NS Energy Staff Writer 31 Mar 2020

Energy Transfer will take over the development of the LNG project and will become the lead project developer
factory-644982_640

Shell exists from Lake Charles LNG project in US. (Credit: Pixabay/GREGOR)

Royal Dutch Shell has announced its plans to back off from the Lake Charles liquefied natural gas (LNG) project in Louisiana due to challenging market conditions.

Energy Transfer will take over the development of the LNG project and will become the lead project developer.

Shell will support Energy Transfer in the bidding process for the engineering, procurement, and construction (EPC) contracts for the LNG project.

Energy Transfer plans to evaluate the alternatives, including the possibility to bring other equity partners and reduce the size of the project from three trains with 16.45 metric tons/year of LNG capacity to two trains with 11.0 mtpa.

The Lake Charles facility comprises four LNG storage tanks, two deep water docks in the Calcasieu Channel and other infrastructure assets.
Shell to provide transition support to Energy Transfer

LNG executive vice president and president Tom Mason said: “Having the ability to capitalize on our existing regasification infrastructure at Lake Charles provides a cost advantage over other proposed LNG projects on the Gulf Coast.

“The Lake Charles project also benefits from its unparalleled connectivity to Energy Transfer’s existing nationwide interstate and intrastate pipeline system that provides direct access to multiple natural gas basins in the U.S.”

In March last year, both the companies have signed a project framework agreement (PFA) to advance the project towards a potential final investment decision (FID).

Under the agreement, Shell and Energy Transfer have agreed to share the cost of developing the project as they have jointly undertaken the EPC bidding process.

Furthermore, Shell has also agreed to support the Energy Transfer during the transition period to facilitate Energy Transfer’s plans to continue the development of the project.

[waldron] 18/3/2020 10:18

US to become the ‘world’s leading LNG exporter by 2025’

Features & AnalysisOil & GasNatural Gas

By James Murray 18 Mar 2020

[maywillow] 18/3/2020 08:15

Shell Energy ties up with Inox India for LNG delivery at doorstep
INOX India, which specialises in cryogenic liquid storage, distribution and re-gasification solutions, will create distribution infrastructure, including logistics and receiving facilities to deliver LNG from this unit to customers.
By Rachita ..

Read more at:

[waldron] 27/2/2020 19:16

GTT optimistic for 2020 after a year of growth
AFP • 02/27/2020 at 17:53

GTT, a specialist in containment systems for maritime transport and the storage of liquefied natural gas (LNG), was optimistic for 2020 after publishing on Thursday rising results in a still buoyant market.

[la forge] 14/2/2020 09:23

LNG | Natural Gas 13 Feb 2020 | 22:12 UTC Houston

Shell to use portfolio LNG volumes to support Louisiana export facility: source

Author Harry Weber Editor Valarie Jackson Commodity LNG, Natural Gas Topic LNG Commoditization

Highlights

Joint venture with Energy Transfer awaits FID

Most US projects struggle to sign new long-term offtake deals

Houston — Royal Dutch Shell will support its half of the joint venture with Energy Transfer to build the Lake Charles LNG export terminal in Louisiana with volumes in its existing portfolio rather than with new long-term offtake contracts tied the facility, a person familiar with the plans said Thursday.
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The decision reflects the advantage the integrated energy major has over most other North American developers in adding liquefaction capacity, thanks to its own operations and relationships in all parts of the LNG value chain, through which it has its hands in one-fifth of the world's production of the super-chilled fuel.

ExxonMobil and Qatar Petroleum advanced Golden Pass LNG in Texas last year without announcing any long-term offtake contracts with external buyers tied to that facility, while the Shell-backed LNG Canada project in British Columbia did the same thing in 2018.

While Lake Charles LNG has yet to make a final investment decision, Shell is confident its about 75 million mt LNG portfolio is sufficient to cover its end of the venture, said the person, who spoke to S&P Global Platts on condition of anonymity to discuss sensitive arrangements. An Energy Transfer spokeswoman did not immediately respond to a request for comment on its plans.

"It's about whether or not you have the portfolio that can be resilient enough to deal with both the buyer side but also on the supplier said," the person said. "It's survival of the fittest."

If FID is reached, Shell plans to use cash to fund its portion of the Lake Charles LNG venture, the person said. Completion of the 16.45 million mt/year capacity terminal is targeted for late 2025. The joint venture partners will have a better idea of exactly when an FID can be made after reviewing bids from construction contractors that are offering to build the terminal, the person said.
MARKET OUTLOOK

Details of Shell's plans come as LNG industry leaders gathered in Houston to discuss at a Platts LNG conference the outlook for additional liquefaction projects in the US, Canada and Mexico, as well as the impact weak prices and demand in Asia, Chinese tariffs and the coronavirus outbreak are having on developers. Most of the proposed US terminals are relying on traditional 20-year take-or-pay contracts tied to their facilities to secure financing for construction. And, virtually all of them are struggling.

"It's truly a year of reflection for all of us," Steve Woodward, a senior vice president at Appalachian Basin gas producer Antero Resources, which supplies feedgas for US liquefaction output, said at the conference. "When is the second wave actually going to kick off? It has all of us scratching our heads as to what the next steps are."

The coronavirus has exacerbated the situation by restricting travel to key Asian commercial markets, forcing some spot LNG cargoes to be diverted to other regions and raising the prospect of Chinese buyers declaring force majeure to try to avoid having to comply with contracts.

"It's all happening in real-time," George Nemeth, director of marketing and business development for Sempra Energy's LNG unit, said at the conference. "We don't know what's going to happen with cargoes that might not be able to find a home. Some will float. Maybe some maintenance gets moved up."
SELLER HUBRIS

In an interview with Platts Wednesday, Freeport LNG CEO Michael Smith said he believes the substantially lower fees that developers of new US LNG export projects are being asked to accept for their supplies compared with what was agreed to for existing facilities, like his Texas terminal, will make it very difficult for most of them to build.

Officials from several of those developers, including Tellurian, Cheniere, and LNG Limited, spoke at the Platts conference Thursday. While none expressed worry of possibly having to abandon projects, they all acknowledged the challenges facing the market, especially for developers relying on new offtake contracts.

"Buyers are spoiled for choice," said Vivek Chandra, CEO of Texas LNG, which has proposed an export terminal in Brownsville. "We are a victim of our own kind of hubris."

[florenceorbis] 07/2/2020 08:12

Asia LNG prices plummet to record lows as China shuts down
Feb. 6, 2020 7:25 PM ET|About: Royal Dutch Shell plc (RDS.A)|By: Carl Surran, SA News Editor

Liquefied natural gas is selling at the lowest price on record in Asia, a troubling sign for U.S. energy producers who have relied on overseas shipments of shale gas amid a weak domestic market.

Asian LNG prices fell to $3/MMBtu today, plunging from above $5/MMBtu as recently as Jan. 15, as a glut in the commodity spreads from the U.S. all over the globe.

"The fundamentals were already really weak" even before the coronavirus outbreak stalled economic activity in China, says Ira Joseph, head of gas and power analytics at S&P Global Platts. "The whole market is really oversupplied."

That's bad news for a wide range of energy firms, from big oil names like Shell (RDS.A, RDS.B) and Chevron (NYSE:CVX), to independent firms that operate export terminals such as Chienere Energy (NYSEMKT:LNG), to shale gas producers such as Range Resources (NYSE:RRC), Cabot Oil & Gas (NYSE:COG) and EQT Corp. (NYSE:EQT)

In the U.S., natural gas prices tumbled below $2/MMBtu last month and have remained there, a remarkable drop given that prices for the heating fuel typically are at their highest levels in winter.

March nat gas futures closed today at $1.862/MMbtu, down 30% from a year ago despite record consumption by U.S. power plants and a surge in exports, both seaborne and across the southern border into Mexico via pipelines.

At prices below $2.25, producers likely will idle drilling rigs and cut production, Bernstein analysts say. "We anticipate this will happen over the coming weeks, which should provide some support to [H2 2020] prices."

[adrian j boris] 06/2/2020 10:20

Total sells interest in Fos Cavaou regasification terminal

Published by David Rowlands, Editor
LNG Industry, Thursday, 06 February 2020 10:00
Total has announced that it has divested its 27.5% interest in Fosmax LNG – the operator of the Fos Cavaou LNG terminal – as a result of a competitive sale process to Elengy, Fosmax LNG’s shareholder with a 72.5% stake, that exercised its pre-emption right.

According to the statement, the consideration for the transaction is approximately US$260 million, including acquisition of a shareholder loan and excluding any earn-outs. Total claims that this sale of a non-strategic midstream infrastructure asset will contribute to the company’s objective of divesting US$5 billion in 2019 – 2020.

The Group retains its regasification capacity of approximately 5.5 million tpy at the terminal, which is equivalent to around 90% of its overall capacity. According to the statement, Total currently has regasification capacity of approximately 18 million tpy in Europe, enabling it to serve local market demand with LNG from the multiple sources in its world-class portfolio.

[waldron] 27/1/2020 16:15

Eni SpA (ENI.MI) said on Monday that it has signed a long-term contract with Nigeria LNG Ltd. to acquire 1.5 million tonnes of liquefied natural gas.

The Italian energy company didn't disclose financial terms, but said the deal would enable it to increase its LNG portfolio from 2021.

Eni said the liquefied natural gas would be produced through existing facilities in Bonny Island, Nigeria.

Nigeria LNG Limited is a joint venture comprising Nigerian National Petroleum Corp., Royal Dutch Shell PLC (RDSB.LN), Total SA (FP.FR) and Eni itself, which has a 10.4% interest.

The Nigerian National Petroleum Corp. and other shareholders in the joint venture agreed in December 2019 to move forward with the construction of the Train 7 project.



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(END) Dow Jones Newswires

January 27, 2020 10:49 ET (15:49 GMT)

[sarkasm] 25/1/2020 09:05

Natural gas price analysis for January: the worst is yet to come?
Valerie Medleva 20 hours ago Analysis
For traders News and features Analysis Natural gas price analysis for January: the worst is yet to come?

After hitting a three-year low in 2019, natural gas has continued its downward movement in 2020. While its price surged by almost 3% on January 10, the following weeks have been anything but dull for the commodity. Natural gas has come under continuous pressure and crashed through two support levels. This winter’s mild weather, combined with the commodity’s oversupply, has pushed prices down to their lowest levels in almost four years.

Is there still a chance that the value of natural gas will rebound by the end of January? Should traders keep the hope for this weak energy asset to finally gain an upward momentum?

In this article, we review the commodity’s recent performance and look at the factors that influence its price. Furthermore, you will find a video from our chief market strategist, David Jones, who gives his latest natural gas price analysis and provides some up-to-date trading tips.
Booming production: blessing or curse?

In October 2019, Donald Trump attended the 9th Annual Shale Insight Conference. During his speech, he noted the “astonishing increase” in shale gas production. Led by rapid development in the Appalachian region, the US has become the world’s largest producer of the commodity.

However, the drawbacks of this boom are hard to overlook. Shale drillers are steadily increasing the amount of gas extracted, leading to extreme oversupply and ruthlessly slashing the commodity’s prices.

Shale oil production continues to rise in the Permian Basin of West Texas and New Mexico by leaps and bounds, creating more gas as a byproduct. The industry seems to be unable to prevent a wave of the additional commodity from flooding the already-oversaturated market. And while exports of liquefied natural gas do provide some relief, the global market remains glutted.

In addition, this winter is proving to be abnormally warm in the US, adding to inventory levels staying above their seasonal average.
What is happening to natural gas prices today?

The prices of natural gas have been troublesome for a while now. The Henry Hub benchmark, named after a key pipeline facility in Erath, Louisiana, has been gradually falling for three years in a row.

On Friday, January 17, the commodity dipped below $2 per million British thermal units (MBtu) for the first time since 2016. The dramatic depreciation continued, with natural gas prices falling as low as $1.79 in a matter of days, representing how a persistent oversupply has buffeted energy producers and investors.

Wall Street Analyst at Morgan Stanley, Devin McDermott, commented: “The industry is a victim of its own success. You don’t just have oversupply in the US – you have oversupply in Europe, Asia, and really across the globe.”



According to him, US producers need the commodity’s value to climb to at least $2.50 level in order to be able to generate free cash flow. However, McDermott then added: “In the near-term, we don’t think it’s realistic to see a $2.50 price.”

Last month, Chevron Corp. (CVX) said it expects a write-down of over $11b, with more than half of that figure associated with its Appalachian gas assets. Shortly after, EQT Corp (EQT), the biggest domestic gas producer, announced it will take an impairment of almost $1.8b for Q4, partially due to low prices. Once at the forefront of US frackers, Chesapeake Energy Corp. (CHK) is now unprofitable and struggling with debt of more than $9b.
Natural gas price analysis: the technical perspective

Do you want to learn what has been recently happening to natural gas from a technical point of view and find out how to profit off the volatility? Wonder where is the price of this energy commodity heading next? Watch David Jones, chief market strategist at Capital.com, review the latest natural gas price movements and make his own technical price analysis:

Always stay on top of the latest natural gas price analysis by subscribing to Capital.com’s YouTube channel.
Is there any relief in sight?

Gas output is expected to fall next year for the first time since 2016. In 2021, the EIA forecasts US dry gas production to drop by 600m cubic feet. Along with the potential tariffs removal, it could finally provide the much-needed positive catalyst that US producers are currently waiting for.

A gas analyst at S&P Global Platts, Rich Redash, said earlier: “Many US LNG exporters likely are hoping, if not praying, that China will import more US gas in the wake of the first phase trade agreement.”

However, before things with supply get better next year, the EIA predicts a 3 per cent increase in output in 2020. With that said, the natural gas price forecast for the near future does not promise to see any positive changes.

Meanwhile, some experts are willing to look beyond the current challenges. Believing in strong global gas demand, mainly fueled by Asia, they say that the sector may remain a good long-term bet.
Trade US Natural Gas Spot CFD



What is your prognosis: will natural gas prices go down throughout the rest of the year? Follow Capital.com to get updates on the latest natural gas market analysis and spot the best trading opportunities.

[ariane] 23/1/2020 10:39

After Hitting A 4-Year Low, Where Could Natural Gas Go?
By Investing.com (Barani Krishnan/Investing.com)1 hour ago (Jan 23, 2020 04:34AM ET)
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The $2 support for winter-time natural gas — a standard-bearer for heating since 2016 — has crumbled, raising the obvious but yet-to-be-answered question: Where could gas go from here?

After the four-year low of $1.804 struck by the February front-month on the New York Mercantile Exchange’s Henry Hub this week, the first sign was that the market was going up — though the subsequent gain itself had done little to assuage those long gas.

Wednesday’s settlement of $1.905 barely brought the market back toward the broken support, meaning a new perch under $2 would have to be found.

Natural Gas Futures Weekly PricesNatural Gas Futures Weekly Prices

The last time Henry Hub’s front-month gas fell this low was in March 2016, when it sunk to $1.611. Yet, by the close of that March, gas was back at near $1.96, posting a near 15% monthly gain. That was after a combined 27% loss in two prior months.

Gas Prices Down Nearly 30% Since October

This winter though, Henry Hub’s front-month is headed for an even deeper trough of nearly 30% from the end of October.

“Although the market is finding buyers near four-year lows, it is far from the beginning of a robust recovery,” Dan Myers, analyst at Houston-based gas risk consultancy Gelber & Associates, wrote in a note issued Wednesday.

He adds:

“Recent shifts in weather forecasts have already done their dirty work to demand expectations late this month and appear to be cementing the warmer-than-normal pattern through early February. With no relief to be found through sustained, strong weather demand, the full weight of two remarkable years of production growth will continue to press on the market."

What does that mean?

For starters, the gas storage draw for the week ended Jan. 17, due to be reported at 10:30 AM ET (15:30 GMT) by the U.S. Energy Information Administration (EIA), is expected to be slightly smaller than the draw for the week to Jan.10.

Analysts tracked by Investing.com expect a figure of 91 billion cubic versus the previous week’s 109 bcf.
Smaller-Than-Average Gas Draws

If correct, it would mark the fourth consecutive smaller-than-average weekly decrease in gas draws.

More troubling is what could follow.

Myers says after another fairly strong heating report next week in the 100 bcf range, “strong withdrawals are no longer expected to last.”

“This time of year is often when the largest withdrawals of the season occur, but the lack of sustained cold weather this year is preventing any substantial draw-downs in storage,” he wrote.

“Total pulls from storage over the next five weeks is forecast to be 8% lower than average and 16% less than last year, allowing this year’s storage surplus to continue to expand through mid-February.”

Unseasonable Weather

Dominick Chirichella, director of risk and trading at the Energy Management Institute in New York, concurs, saying more unseasonable weather was expected in the coming days.

Accumulating snow was expected across the Midwest through northern New England late this week/this weekend.

“The mild pattern will set up shop across most of the U.S. over the next two weeks overall,” Chirichella wrote in his report, also issued Wednesday. “Temperatures will generally be above normal across the Central and Eastern U.S. for days 11-15.”

While some cooler air will attempt to reach the North Central and Northwest U.S. later in the period, “modest warm anomalies should occur across the Southwest,” he said.

“Confidence is not high on this cooling trend as recent model attempts to bring cooler air into the U.S. at the day 11-15 range have failed and the guidance trended warmer,” Chirichella added.

“Cool risks are starting to creep in, but we are cautious with it for now. Changes were minor overall, but we did trend the North Central U.S, a little warmer.”

Speculators “As Short As They Can Be”

As a group, speculators were about as net short on natural gas now as they’ve ever been, according to INTL FCStone Financial Inc. Senior Vice President Tom Saal.

“The way I calculate it, it’s the largest net short since 2006,” Saal said in an interview with naturalgasintel.com, noting that 2006 is as far back as his dataset goes.

“As far as getting more short, that’s the $64,000 question. Can the speculators get more short? And the answer is, of course they can. To get more net short, I would think you’d need more money, more new shorts” to enter the market."

Saal said he was “surprisedR21; by the “aggressive selling” that has seen the February contract drop from above $2.20 as recently as last week to now down well below the $2 mark. This move lower occurred with “pretty good volume,” he said.

As for Wednesday’s price action, he said: “It didn’t look like any new selling coming into the market, and it didn’t look like any new buying either. I think people were trying to figure out what happened.”

But some volatility could also be in store as the extent of the net short position now raises the prospect of a rally on buying momentum from short-covering, said Saal.

“What you have now is a situation where they may have unrealized gains,” he said.

“That looks good on paper, but until you actually cash in the trade you haven’t made any money yet. So yeah, there’s some major league buying coming, and if it’s the speculators covering shorts, it’ll be motivated buyers.”

[gibbs1] 22/1/2020 08:32

Striking Oil Ain’t What It Used to Be
Poor Countries Find Fossil Fuels Just As the Rich World Swears Them Off
By Amy Myers Jaffe January 20, 2020



An oil rig in Guanabara Bay, Brazil, June 2015 Felix Clay / eyevine / Redux

On January 7, the oil and gas companies Apache Corporation and Total SA announced a major oil find off the coast of Suriname, not far from enormous offshore deposits in neighboring Guyana discovered by ExxonMobil last year. The size of the Suriname discovery is yet to be determined, but it could be large enough to transform the small South American country, where per capita income is less than $6,000. Just three months prior on the other side of the Atlantic, the British oil major BP announced the largest natural gas discovery of 2019: the energy equivalent of 1.3 billion barrels of oil lies waiting to be extracted off the coast of Mauritania, more than enough to support a liquefied natural gas (LNG) hub. And the same year in Mozambique, Total acquired a $3.9 billion stake in an LNG project whose total cost will likely dwarf that country’s national economy.

At a time when many countries are finally trying to reduce their reliance on fossil fuels, the world is suddenly awash in oil and gas discoveries. But for the countries with the newest finds, many of them in Africa and South America, mineral wealth may not be the bonanza it was in decades past. Large oil and gas companies see long-term prices trending downward. As a result, they are investing in fields that can be brought into production quickly instead of developing expensive, far-flung reserves. Global natural gas markets, in particular, face a huge glut of resources and projects that must compete against the falling price of renewable energy technologies. As a result, Suriname, Guyana, Mauritania, Mozambique, and a handful of other developing countries with recent fossil fuel finds are in a desperate race against time.
GOING ONCE, GOING TWICE

The party hasn’t ended yet, but for the world’s newest petrostates it may be last call. To preempt a possible price slump, many oil and gas companies are pursuing aggressive timelines for new projects to lower costs and return cash quickly to nervous shareholders. ExxonMobil has pulled out all the stops to get its Guyana find online as fast as possible: its discovery-to-extraction timeline is the shortest ever for a greenfield project of its scale. In Mozambique, Total appears to be fast-tracking development of the LNG project, after other investors dragged their feet for years. (Anadarko Petroleum discovered the gas reserves in 2010.) The Suriname and Mauritania finds may well be developed, but the former is still in the exploration phase and the latter will have to overcome a number of financing and other obstacles.
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Even on accelerated timetables, recent discoveries may not yield the same windfalls that previous finds did.

Even on accelerated timetables, however, these recent discoveries may not yield the same windfalls that previous finds did. New oil and gas states will have to compete with surging fossil fuel exports from the United States, which absorbed most, if not all, of the rising demand for petroleum in 2019 and may continue to do so for the next few years. What is more, other developed countries such as Norway and Canada are developing their own recent fossil fuel finds with the benefit of new technologies that lower the cost of drilling and facilitate greater production. Competition between these markets and new developing ones will only stiffen if global economic growth falters down the road, reducing the immediate demand for oil.

Making matters worse for new oil producers, some of the world’s biggest markets—such as China and the European Union—have enacted policies that incentivize a rapid move away from oil. France, the United Kingdom, China, and India have all announced future bans on the sale of gasoline-powered cars. And rising targets for renewable energy in the United States, Europe, and Asia have clouded the prospects for natural gas. For all of these reasons, recent finds in the developing world are unlikely to be as lucrative as similar discoveries in the past.
COMPETING GOALS

Other finds may never be developed at all. New producers are on the hunt for capital just as many existing oil producers in the developing world are struggling to find continued investment for their remaining resources. In a recent tender for offshore drilling rights in Brazil—billed by President Jair Bolsonaro as the “biggest auction there’s ever been”—the government found few takers. Angola’s oil production is falling because of a lack of interest in new drilling.

Part of the problem is the broader market forces described above. But part of it is mounting hostility from international financial institutions such as the World Bank and the European Investment Bank, both of which have sworn off lending to new fossil fuel projects because of climate change. In the past, these institutions played a critical role in helping poorer nations get lucrative oil and gas projects, including major pipeline projects in Africa, off the ground. The World Bank alone issued $21 billion in fossil fuel–related loans, grants, and guarantees between 2014 and 2018. Governments and sovereign wealth funds are increasingly climate conscious as well: last year, the UN-backed Green Climate Fund—which finances investments in climate adaptation, clean energy, and energy efficiency projects in the developing world—attracted commitments of close to $10 billion from 27 countries to spend on climate aid over the next four years.

The apparent hypocrisy of rich nations swearing off fossil fuels just when many poor nations are discovering their own has fueled debate about how best to balance climate and development goals. Climate justice advocates have gone as far as calling for long-standing and wealthy oil producers such as Norway to shut down their oil industries to make room for poorer nations with oil reserves. The 2017 Lofoten Declaration—signed by some 600 organizations in 76 countries—was a step in that direction, pushing for wealthy nations to lead the way in abandoning fossil fuel production because their economies have already benefited from burning oil and gas and are in a better position to diversify. But the Lofoten Declaration applies only to extant producers, and it is difficult to imagine a fair or uncontroversial way to determine which countries with new discoveries should be given priority to develop their oil and gas reserves.

In the end, markets will determine which new discoveries get exploited and which remain stranded in the ground or underwater. Projects with lower costs will advance further than those with a comparatively higher overhead. That will pit new oil states against wealthy Middle Eastern producers, which have among the lowest oil and gas production costs. At a recent OPEC meeting, the Angolan oil minister reportedly stormed out when his Saudi counterpart suggested that his country—which faces low rates of investment and high production costs—should lower production alongside OPEC’s richer members in order to shore up oil prices. Such heated debates among OPEC members reflect the high stakes for countries that depend heavily on oil and gas revenues for their state budgets. For nascent oil producers trying to break into that well-heeled club, however, the competition will be tougher than ever.

[grupo guitarlumber] 17/1/2020 15:06

Shell exec touts benefits of Clifton LNG terminal
January 17, 2020
Chester Robards
0
174Views

The development of a liquefied natural gas (LNG) regasification terminal by Shell North America will generate a mixed bag of benefits for Shell and the Bahamian public, according to Shell’s General Manager of Market Development Markus Hector, who explained that the terminal, which will be called Terminal Co., will not only produce power for New Providence, but will also service the shipping industry and industrial businesses.

According to Hector, who spoke to reporters outside of the Bahamas Business Outlook at Baha Mar resort, the development of the facility near Bahamas Power and Light’s Clifton Pier power station, will mean a plethora of benefits for The Bahamas, including a leading position in the provision of LNG for the new generation of cruise vessels that will be powered by LNG-burning engines.

“LNG is, in terms of hydrocarbon fuels, the lowest CO2 emissions fuel and it doesn’t have particulate matter or other emissions with it, so it’s a preferred fuel to go forward,” he said.

“And we think that based on having the infrastructure here and having the fuel here in The Bahamas, there is opportunity in terms of industrial use, there is opportunity in terms of Family Islands, there is opportunity to use it as a fuel for cruise liners in particular and other vessels which are massively, on a global scale, switching to LNG and creating an opportunity here for The Bahamas to be the front runner in this new business and create a lot of economic benefit for the people of The Bahamas.”

He added that LNG across the world has been “developing in a transformational way” because it is a cleaner, lower carbon-emitting fuel.

According to Hector, LNG will not only mean cleaner burning power plants on New Providence, but across The Bahamas.

“I have no doubt in my mind that having LNG in The Bahamas brings great opportunity for the future,” he said.

“Dr. Donovan Moxey talked about the ambitions that BPL has in supplying cleaner power across the islands of The Bahamas, including renewables; and certainly including LNG as a backup fuel to basically give the reliability.”

Author Recent Posts

Chester Robards
Senior Business Reporter at The Nassau Guardian
Chester Robards rejoined The Nassau Guardian in November 2017 as a senior business reporter. He has covered myriad topics and events for The Nassau Guardian.
Education: Florida International University, BS in Journalism

[waldron] 14/1/2020 06:57

Why U.S. LNG Can’t Win In Europe
By Irina Slav - Jan 13, 2020, 6:00 PM CST
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When Washington imposed sanctions on companies, the move drew criticism not just from Russia but from Germany as well. The sanctions, targeting firms building the pipeline that will increase Gazprom’s export capacity for Europe, were seen as interference in Germany’s internal affairs while the legislators who approved them saw them as a tool for deterring Russia’s energy influence in Europe. For some, however, the reason for the sanctions was the U.S.’s own energy plans for Europe.
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The Trump administration is following an agenda of energy dominance, and this dominance has to include Europe, which is one of the biggest markets for natural gas and, what’s more relevant to the U.S., liquefied natural gas. However, lessons from history, and that’s a history of Gazprom, would suggest that the energy dominance approach won’t work--not in Europe.

Bloomberg’s Liam Denning recently reviewed a book by an IHS Markit expert on Russian energy, Thane Gustafson, titled The Bridge. The Bridge, according to Denning, contains, among other things, a cautionary tale for U.S. gas ambitions in Europe. The gist of it is that the European gas market is a lot more open and transparent than it used to be, and while this has served to reduce the influence of Gazprom on the continent, it has also served to deter anyone else that might want to try to take Gazprom’s place.

The truth is that today, Europe has developed a continental gas network, and that network features LNG terminals. This means that many European countries are today a lot more flexible in their gas imports than they were 30 years ago, when Russia and Norway dominated the market. There is just one catch: the LNG has to be cheap enough to beat alternative supplies.
Related:The Iran Crisis Is Far From Over

Poland is already buying U.S. liquefied natural gas. The country is ready and willing to pay more if it has to, in order to reduce its dependence on Russian gas for a number of historical reasons. Yet last year Bulgaria, too, bought two cargos of U.S. LNG from Cheniere’s Sabine Pass liquefaction plant. According to the head of the state gas operator, the cargos were priced at the level of local benchmark prices.

Even so, Poland and Bulgaria are small potatoes. Germany is the biggest gas market in Europe and it will become even bigger as the country aims to shut down all its remaining nuclear power plants by 2022. This is why Gazprom is building Nord Stream 2 with Angela Merkel’s blessing, after all. And this is why the U.S. is sanctioning it if we leave aside the ideology that every government uses to advance its purely pragmatic agenda.

Germany imported $14.6 billion worth of natural gas in the first half of 2019. That was 14.8 percent higher than a year earlier, but the increase in volume terms was even greater: these came in at 2.66 million terajoules, which was 20 percent higher than the year-earlier period. Historically, most of the imported gas has come from Russia, followed by Norway and the Netherlands. Now that the Netherlands is shutting down its flagship Groningen field ahead of schedule, Germany will need more gas from Russia and Norway. It could import U.S. LNG as per a EU promise to President Trump, as long as the price is right, as the EU Energy Commissioner said last year.

Yet because of the open and transparent nature of Europe’s gas market, Germany is also buying LNG from Russia. Just last month Novatek opened its first LNG fueling station in Germany. It is the first LNG station of the Russian company in Europe and could mark the start of a network.

This is why energy dominance is a challenging goal in Europe’s gas market. The fact that Germany and others are building new LNG terminals does not obligate them to use these terminals for U.S. LNG. Qatar is right around the corner, so to speak, and so are Nigeria and Algeria – both large LNG producers. Competition is intense and it’s out in the open. The victory that EU competition watchdogs achieved in their fight with Gazprom’s long-term contracts paved the way to the current competitive environment that leaves both Gazprom and U.S. LNG producers at the mercy of market forces.

By Irina Slav for Oilprice.com

[adrian j boris] 09/1/2020 09:23

Nigeria expansion deal will boost LNG by 30 per cent.

Nigeria expansion deal will boost LNG by 30 per cent.
News Desk
Nigeria inks major LNG deals with global oil giants

ABUJA/LAGOS

Nigeria has signed a major gas expansion deal, a much-needed collaboration with oil majors that Nigeria LNG said would boost its liquefied natural gas output by more than 30 per cent.

The agreement marks a moment of amity with international oil majors, even as a tax dispute and a new law increasing the government’s take on deepwater oil production have irked some companies.

The final investment decision on the Train 7 processing unit at the Bonny Island plant was signed by Nigeria LNG partners state-run Nigerian National Petroleum Corporation (NNPC), Total and Royal Dutch Shell in Abuja.

The new train is expected to boost output by 35 per cent to 30 million tonnes per year, NLNG said in a statement, and will arrest a decline in Nigeria’s LNG output. NLNG operates six LNG processing units, known as trains, on Bonny Island.

The train 7 project has been delayed for several years. A previous deadline for a final investment decision in the fourth quarter of 2018 was not met. The west African country is rich in oil and gas but has been struggling to boost its output of both resources.

Its declining LNG production last year pushed it down to the world’s fifth largest producer, with the US taking its place at number four.

Total, Chevron and ExxonMobil are trying to pare back some Nigerian assets as they focus on projects elsewhere, including US shale.

Earlier this month, NLNG signed 20-year supply agreements with Shell, Eni and Nigerian oil company Oando to feed the Train 7 project.

[maywillow] 07/1/2020 20:23

GTT receives an order from the Korean DSME for the design of the tanks of an LNG carrier
Gaztransport And Technigas (EU: GTT)
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Today: Tuesday, January 7, 2020
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PARIS (Agefi-Dow Jones) - The manufacturer of cryogenic membranes for the transport of liquefied natural gas Gaztransport and Technigaz (GTT) announced Tuesday that it has received an order from the Korean shipyard Daewoo Shipbuilding & Marine Engineering (DSME) for the design of liquefied natural gas (LNG) tanks for a new LNG carrier. This 174,000 cubic meter capacity vessel will be built on behalf of a European shipowner. Delivery will take place during the first quarter of 2022, GTT said in a statement. ([e-mail]) ed: LBO


Agefi-Dow Jones The financial newswire


(END) Dow Jones Newswires


January 07, 2020 12:08 ET (17:08 GMT)