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[the grumpy old men] 19/12/2017 17:49

Gazprom to splurge on EU gas pipe as U.S. weighs penalties
By Elena Mazneva on 12/19/2017

MOSCOW (Bloomberg) -- Russia’s natural gas exporter is channeling more money into the fight for market share as the U.S. threatens its biggest European pipeline project with possible sanctions and delivers tankers of fuel to the region.

Gazprom PJSC plans to spend 802 billion rubles ($13.7 billion) on routes to Europe and China in 2018, almost 41% more than this year, according to a draft budget prepared for a board meeting Tuesday that was seen by Bloomberg News. The biggest project is its Nord Stream 2 link to Germany, which had planned to start borrowing from banks next year before being singled out as a potential target by the U.S. in August.

Russia sees the threat of U.S. measures against Nord Stream 2 as an attempt to clear space for exports of liquefied natural gas in its most lucrative market. The expansion has divided opinion in the European Union, which has warned of retaliation if the U.S. hurts EU energy majors involved in the project, while the bloc also seeks to diversify energy supplies away from Russia. Poland and Ukraine, key transit routes for Russian gas, have lobbied against the 9.5 billion-euro ($11.2 billion) project that bypasses them by crossing the Baltic Sea.

Gazprom has little choice other than financing the future pipeline on its own for now, Alexander Kornilov, an energy analyst at Aton LLC, said. “It’s a very logical step.”

Gazprom and its five EU partners, including Germany’s Uniper SE and Austria’s OMV AG, stumped up 30% of the link’s budget by August. Their plan to have the project operator, fully owned by Gazprom, borrow the rest from banks may need to change given the U.S. law, OMV said in September.

Gazprom, which has a monopoly on pipeline exports of gas from Russia, will contribute an additional 1.52 billion euros for the under-sea section of the link next year as the company aims to keep the project on schedule to start gas flows in late 2019 and is ramping up spending on the Russian network, according to the document.

The initial funding terms are still in place, one of the partners, Uniper, said by email. OMV, Royal Dutch Shell Plc, France’s Engie SA and Wintershall, a unit of Germany’s BASF SE, either declined to comment or didn’t respond.

“Before getting all the approvals to build Nord Stream 2, it’s complicated to raise project financing,” Gazprom spokesman Sergei Kupriyanov said, without confirming any figures or commenting on the sanctions risk. “Really, this can be done after finishing the approvals process.”

Gazprom plans to supply 20 Bcm of gas to Germany through the new link in 2020, cutting the company’s current transit through Soviet-era pipelines in Ukraine, according to the document.

Annual exports to Europe are forecast at about 188 Bcm through 2020, close to the record high expected this year, according to the budget. Outlooks are based on Gazprom’s contract portfolio and current supply levels, Kupriyanov said.

Links to China and Turkey are also expected to start supplies by the end of 2019. Spending on the Turkish Stream pipeline will exceed 2.43 billion euros next year, up 72% from this year, the draft budget shows. The link is expected to pump almost 24 Bcm in 2020, according to the document.

The Power of Siberia pipeline to China will need 218 billion rubles next year, a 4% increase, and is set to deliver 5 Bcm in 2020.

While Gazprom sees investments slowing from 2020 after the key export pipelines are built, it plans to keep dividends flat at this year’s level of 190 billion rubles, the document shows. The company usually revises its budgets, which don’t include its oil arm Gazprom Neft PJSC or utilities in Russia and Europe-based gas traders, twice a year.

[waldron] 04/12/2017 19:29

Barron's
Natural gas won’t get a lasting lift from cold December weather
By Myra P. Saefong

Published: Dec 4, 2017 2:08 p.m. ET





AFP/Getty Images

Tight U.S. supplies and fears about a wave of cold weather prompted a roughly 5% rise in natural-gas prices last week. Don’t expect it to last long in a market that has lost nearly 17% year to date.

“It’s important to remember how fickle and short term the natural-gas trading community is,” says Keith Schaefer, owner and editor of the Oil & Gas Investments Bulletin. Traders “bought up natural gas hard last December on just one or two cold-weather forecasts, and then the longs got clobbered as [the forecast weather] never materialized.”

Adds Schaefer: “If really cold weather doesn’t show up by Feb. 1, then prices will go lower all through 2018.”

The past two winters have been warm. December through February, temperatures for 2015-16 were the warmest on record, and last winter overall was the sixth warmest, according to Paul Pastelok, senior meteorologist at AccuWeather. “This leads to higher inventories and a drop in prices,” he says.

Pastelok expects more draw on natural-gas supplies this winter, with “very cold air” forecast for the U.S. in the second week of December. He sees more natural-gas demand for home heating from the Midwest and northern plains to the Northeast, compared with last winter.
See Also
Behind the Scenes With Annemarieke van Drimmelen

U.S. supplies of natural gas in storage are tight, meanwhile. Inventories in the lower 48 states stood at roughly 3.7 trillion cubic feet for the week ended on Nov. 17, the lowest level for the third week of November in three years, according to data from the Energy Information Administration. They’ve fallen for three weeks in a row.

The cold-weather expectations amid tight supplies prompted the rally.

But the uptick in futures prices has already advanced further than Schaefer expected—he didn’t think they’d top $3 this year. That’s in part why he’s bearish on the outlook for natural gas. Futures prices for natural gas NGF18, -2.94% settled above $3.21 per million British thermal units on Nov. 10, a nearly six-month high. They settled on Friday at $3.06.

“Wall Street’s fear is that [liquefied natural gas] exports would ramp up enough to keep the [domestic] market quite tight,” and cold winter forecasts are the main reason that prices have topped $3, says Schaefer. LNG exports could jump another two billion cubic feet a day over this winter with more trains at Cheniere Energy’s LNG, -0.30% Sabine Pass export terminal and Dominion Energy’s D, -0.02% Cove Point export terminal becoming operational, he says. That would draw more supplies of the fuel away from the domestic market.

U.S. improvements in natural-gas transportation have also helped to relieve supply congestion in the Northeast. More pipeline capacity to move gas away from the Marcellus and Utica shale areas has contributed to a rise in the price of the commodity in the Northeast, as gas produced there gets to areas that need it more quickly and easily, says Phil VanHorne, president and chief executive offer at BlueRock Energy.

Still, record production could keep a lid on prices throughout the winter,” says VanHorne.

Schaefer agrees. “U.S. natural-gas production, and even Canadian production, started to increase in a larger and larger way through the summer and fall of 2017,” he says. Output is no longer rising only in the Marcellus shale basin, he notes. “It’s increasing in the Permian and Haynesville, and even in the Rockies.”

Baker Hughes data pegged the number of active U.S. natural-gas drilling rigs at 180 for the week ended on Dec. 1, up from 119 rigs a year earlier. Schaefer says only 120 rigs are needed to hold U.S. production steady.

Prices, therefore, are likely to “hold ground or stay flat by the end of the year,” Schaefer says. Weather could easily change all of that, of course, but he doesn’t expect any price gains to last.

“U.S. natural-gas prices live and die by how cold the U.S. East Coast is in January and February,” says Schaefer, and right now, it isn’t supposed to be that cold.

“If the East Coast does get a prolonged cold snap or a polar vortex event, [natural-gas prices] could spike higher on some emotion and fear, but the truth is, we have lots of gas…and higher prices will just stimulate even more production,” says Schaefer.

This article was originally published on Barrons.com on Dec. 2.

[waldron] 04/12/2017 19:24

Barron's
Natural gas won’t get a lasting lift from cold December weather
By Myra P. Saefong

Published: Dec 4, 2017 2:08 p.m. ET





AFP/Getty Images

Tight U.S. supplies and fears about a wave of cold weather prompted a roughly 5% rise in natural-gas prices last week. Don’t expect it to last long in a market that has lost nearly 17% year to date.

“It’s important to remember how fickle and short term the natural-gas trading community is,” says Keith Schaefer, owner and editor of the Oil & Gas Investments Bulletin. Traders “bought up natural gas hard last December on just one or two cold-weather forecasts, and then the longs got clobbered as [the forecast weather] never materialized.”

Adds Schaefer: “If really cold weather doesn’t show up by Feb. 1, then prices will go lower all through 2018.”

The past two winters have been warm. December through February, temperatures for 2015-16 were the warmest on record, and last winter overall was the sixth warmest, according to Paul Pastelok, senior meteorologist at AccuWeather. “This leads to higher inventories and a drop in prices,” he says.

Pastelok expects more draw on natural-gas supplies this winter, with “very cold air” forecast for the U.S. in the second week of December. He sees more natural-gas demand for home heating from the Midwest and northern plains to the Northeast, compared with last winter.
See Also
Behind the Scenes With Annemarieke van Drimmelen

U.S. supplies of natural gas in storage are tight, meanwhile. Inventories in the lower 48 states stood at roughly 3.7 trillion cubic feet for the week ended on Nov. 17, the lowest level for the third week of November in three years, according to data from the Energy Information Administration. They’ve fallen for three weeks in a row.

The cold-weather expectations amid tight supplies prompted the rally.

But the uptick in futures prices has already advanced further than Schaefer expected—he didn’t think they’d top $3 this year. That’s in part why he’s bearish on the outlook for natural gas. Futures prices for natural gas NGF18, -2.94% settled above $3.21 per million British thermal units on Nov. 10, a nearly six-month high. They settled on Friday at $3.06.

“Wall Street’s fear is that [liquefied natural gas] exports would ramp up enough to keep the [domestic] market quite tight,” and cold winter forecasts are the main reason that prices have topped $3, says Schaefer. LNG exports could jump another two billion cubic feet a day over this winter with more trains at Cheniere Energy’s LNG, -0.30% Sabine Pass export terminal and Dominion Energy’s D, -0.02% Cove Point export terminal becoming operational, he says. That would draw more supplies of the fuel away from the domestic market.

U.S. improvements in natural-gas transportation have also helped to relieve supply congestion in the Northeast. More pipeline capacity to move gas away from the Marcellus and Utica shale areas has contributed to a rise in the price of the commodity in the Northeast, as gas produced there gets to areas that need it more quickly and easily, says Phil VanHorne, president and chief executive offer at BlueRock Energy.

Still, record production could keep a lid on prices throughout the winter,” says VanHorne.

Schaefer agrees. “U.S. natural-gas production, and even Canadian production, started to increase in a larger and larger way through the summer and fall of 2017,” he says. Output is no longer rising only in the Marcellus shale basin, he notes. “It’s increasing in the Permian and Haynesville, and even in the Rockies.”

Baker Hughes data pegged the number of active U.S. natural-gas drilling rigs at 180 for the week ended on Dec. 1, up from 119 rigs a year earlier. Schaefer says only 120 rigs are needed to hold U.S. production steady.

Prices, therefore, are likely to “hold ground or stay flat by the end of the year,” Schaefer says. Weather could easily change all of that, of course, but he doesn’t expect any price gains to last.

“U.S. natural-gas prices live and die by how cold the U.S. East Coast is in January and February,” says Schaefer, and right now, it isn’t supposed to be that cold.

“If the East Coast does get a prolonged cold snap or a polar vortex event, [natural-gas prices] could spike higher on some emotion and fear, but the truth is, we have lots of gas…and higher prices will just stimulate even more production,” says Schaefer.

This article was originally published on Barrons.com on Dec. 2.

[sarkasm] 27/11/2017 09:33

TOO HOT TO HANDLE

[the grumpy old men] 24/11/2017 06:23

Oil & Gas
Opinion: The dash for gas is hotting up

Written by Paul Sullivan - 24/11/2017 6:00 am

Paul Sullivan
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Never before have the opportunities and challenges facing the global gas industry been the subject of such intense scrutiny and debate as they are today. With natural gas and LNG now sitting at the forefront of a new global energy competition, the sector’s most influential leaders will have plenty to discuss at next year’s Gastech in Barcelona.

Leading analysts Wood Mackenzie forecast global gas demand surging by as much as 41 per cent over the next two decades, with LNG demand at the forefront of this new global ‘dash for gas’ as governments seek cleaner energy solutions to national demand. The investment required in driving such expansion of the global gas and LNG industry could reach a dizzying US$9 trillion, according to Wood Mackenzie, with most of that to be invested in major new infrastructure.

Who will be the world’s most influential supplier?
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Yet the challenges of delivering this new demand for gas are also sizeable and centre on the key question of who will provide what to whom? Pipeline gas or LNG? And from which supplier? As an example, the recent Gastech 2018 Governing Body meeting in London discussed how the world was currently experiencing a tussle between international gas producing countries to determine who would ultimately take the spoils and lay claim to the title of world’s most influential supplier.
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Europe, China and India are among the key theatres of the global gas race. Europe has traditionally relied on pipeline natural gas imports from Russia to feed demand.

However, the burgeoning growth in North American LNG exports, triggered by the rapid expansion in US shale gas production in recent years, recently led the International Energy
Agency to claim that the US will become one of the world’s top gas exporters by
2020, and will challenge Russia by 2022.

“There is competition between North America, Australia, Qatar and Russia, and their targets
are importers of LNG or pipeline gas. They are looking to project their energy armies anywhere in the world,” said a Gastech Governing Body member during the meeting in London in September. “It is a competition about who will win the energy race. Who will be the number one energy provider to Europe, China and India?”

A “pivotal role” in today’s energy system

This is not the only issue that the gas industry faces. Other topical points raised by the governing body, which met to agree the commercial and technical sessions for Gastech 2018’s conference, included managing LNG emissions controls to meet governmental regulations and ways to tackle releases of elemental methane; the challenges inherent in financial risk management across projects and assets; and the growing demand for gas and LNG as a fuel for marine and shipping projects following the UN International Maritime Organisation’s cap on sulphur content in marine fuel by 2020.

After decades of favouritism by energy consumers towards cheap and plentiful coal, the world is now embracing the pivatol role that cheap and plentiful – and cleaner – natural gas can play, as energy markets develop increasingly capable infrastructure planning and investment capabilities. With advances in technology, efficiency and market fluidity, the competitiveness of natural gas is set to drive more customers towards this ‘future friendly’, cheap and clean energy solution – with the Gastech conference at the heart of the conversation, navigating the next steps the industry takes.

Gastech exhibition and conference runs from 17-20 September 2018 at Fira Gran Via in Barcelona, Spain. A call for papers to speak at Gastech conference – based on topics and sessions chosen under consultation by the Governing Body – is currently underway. For more information or to submit an abstract, please visit: www.gastechevent.com/speak

By Paul Sullivan, Steelhead LNG and Commercial Co-Chairman, Gastech Governing Body

[sarkasm] 23/11/2017 07:46

World May Face Liquefied Natural Gas Supply Shortage by 2025
© RIA Novosti. Sergey Guneev
World
07:48 23.11.2017(updated 08:10 23.11.2017) Get short URL
137840

The global gas market may potentially face shortages of liquefied natural gas (LNG) by 2025 due to the lack of new extraction projects coupled with surging demand with gas replacing coal and nuclear power, Qatari Energy and Industry Minister Mohammed Saleh Abdulla Al Sada said Wednesday during the Gas Exporting Countries Forum (GECF) in Bolivia.

SANTA CRUZ DE LA SIERRA (Sputnik) — The Qatari Energy and Industry Minister forecasts demand to continue growing throughout the next decade and reach almost 500 million tons annually by 2030 due to gas replacing coal and nuclear power and development of power markets as well.

"While an oversupply appears over the next few years, it will not be to an extent as previously perceived. Supply of liquefied natural gas is expected to peak at 2020 and very few new LNG projects are expected to come in the earlier part of the next decade. As a result, the global LNG market will start to tighten, potentially facing a supply shortage by 2025 onward," Al Sada said, adding that LNG supply would reach 400 million tons annually by 2020.

Qatar itself intends to increase LNG production from 77 million tons to 100 million tons annually by 2040.

Qatar to Back Russian Rotating Chief of GECF

The Qatari energy minister, who was speaking at GECF's extraordinary ministerial meeting in Bolivia, said he hoped that Russian Deputy Energy Minister Yuri Sentyurin would take the forum of the world's top gas producers to "further heights of successes."

"I would also like to welcome in advance Yuri Sentyurin, incoming Secretary General. We would like to assure Dr. Yuri that we will extend every support to him and we would like to welcome him to Doha," Al Sada said Wednesday.

Yuri Sentyurin was chosen last month to take over from Iran’s Seyed Mohammed Hossein Adeli, starting next January.

Gazprom to Sign Gas Production Deals With Bolivia

Speaking during a panel session at the GECF in the Bolivian city of Santa Cruz, the Gazprom senior official said Bolivian gas "should form a basis for the integration of gas value chains in the neighboring countries."

"Today we are going to sign a few documents with our Bolivian partners in order to also expand our presence here not only in Bolivia, but showing interest in terms of supply to some areas which are quite close to gas production," Andrey Fick, head of Gazprom International, the firm's overseas branch, said Wednesday.

The stand with the Gazprom company's logo at the Sochi International Investment Forum 2016
© Sputnik/ Maksim Blinov
Qatar Offers Russia to Take Part in Projects on LNG Production – Gazprom
In May, Bolivia's Hydrocarbons and Energy Minister Luis Sanchez said Gazprom was interested in exploring three blocks of San Telmo Sur, San Telmo Norte, and Astillero deposits.

The energy giant and Bolivian authorities agreed in October to establish a joint venture to sell Bolivian gas in Argentina and Brazil.

GECF energy ministers have been holding a session in Bolivia since Tuesday. The energy forum, comprising Algeria, Bolivia, Egypt, Equatorial Guinea, Iran, Libya, Nigeria, Qatar, Russia, Trinidad and Tobago, Venezuela and the United Arab Emirates, will wrap up on Friday.

[la forge] 18/11/2017 18:14

Can Australia Surpass Qatar As World’s Top LNG Supplier?
By The Polish Institute of International Affairs - Nov 18, 2017, 12:00 PM CST LNG

An advantageous geographical location and liberalised trade in energy resources allow Australia to successfully compete for the most lucrative and promising liquefied natural gas (LNG) markets. Come 2020, Australia likely will be the world’s largest LNG supplier. However, its domestic LNG industry will have to face the challenge of securing enough natural gas for export. For LNG importers like Poland, the success of those efforts would ensure favourable market conditions.

Australia is the second-largest exporter of LNG, with Qatar topping the list. Australian authorities expect that the volume of LNG exports in 2017 will be as high as 52 million tonnes and Australia’s share of the global market to reach 17 percent. This would mean a doubling of exports compared with 2014, and is attributable to the launch of four new liquefaction facilities between 2015 and 2017. By 2019, once the existing terminals will have been expanded and two additional ones come on line, Australia’s liquefaction capacity will climb to 88 million tonnes per year (MTPA). At that point, Australia will surpass Qatar, with the U.S. in third place. Natural gas will become Australia’s third most important export commodity, after iron ore and coal.

Assets

Australia’s liquefaction facilities, both in the west and the east, are closer to the largest LNG importers—Japan, South Korea, and China, together accounting for 55 percent of world demand—than those in Qatar or the U.S. It takes two weeks to ship LNG from the Persian Gulf to Japan. While the expansion of the Panama Canal allowed for increased gas tanker traffic from the U.S., the journey from the Gulf of Mexico to East Asia still takes three weeks. Shipments from Australia need just one week to reach clients in the region. The lower freight costs will remain the backbone of Australia’s competitiveness as an exporter, especially in light of high production costs (Australian LNG plants are the most expensive in the world, costing as much as 50 percent more than those in the U.S.) and the excess of liquefaction capacity on the market. Even though producers such as Indonesia and Malaysia enjoy an even more favourable position, especially when it comes to supplying the Indian market (7 percent of global LNG demand), they do not plan any meaningful investment in new liquefaction capacity in the coming years. By 2022, their market share will drop markedly as Australian and U.S. facilities come on line. A facility in Sakhalin, Russia, with a capacity of 10 MTPA, will be in the position to supply a fairly limited share of the market.

Related: China’s Mysterious Arctic Silk Road

The competitiveness of Australian LNG is further enhanced thanks to the elimination of import tariffs by key customers, as well as the application of flexible, affordable, short-term (spot) contracts. As a result, Australia was able to quickly win a sizeable share of the market. A free trade agreement (FTA) with South Korea went into force in December 2014, followed by FTAs with Japan (January 2015) and then with China (December 2015). LNG deliveries to Japan climbed by 25 percent between 2014 and 2016, with Australia’s market share growing from 20 percent to 27 percent. In the case of China, the elimination of trade barriers coincided with the dynamic growth of Chinese demand for LNG: from 13 MTPA in 2011 and 20 MTPA in 2014 to almost 27 MTPA in 2016. Between 2014 and 2016, Australia’s market share surged from 19 percent to 46 percent. In that same period, the Qatari share of the Japanese LNG supply market dropped from 18 percent to 14 percent, and from 33 percent to 18 percent in deliveries to China. Australia moved ahead of Malaysia and Indonesia as a supplier to South Korea. The volume of exports expanded by 5.5 times to reach almost 5 MTPA, making Australia the second-largest supplier to this market with a 14 percent share (Qatari suppliers keep supplying about 35 percent of the LNG imports).

Limitations

The most serious challenges have to do with the surge of domestic natural gas prices as a result of increasing volumes of LNG exports, and with the risk of supply shortages for domestic customers. The first phenomenon has already been observed in the eastern and southern parts of the country and is linked to gas transmission infrastructure. These regions house Australia’s largest natural gas consumers (in the power generation sector, petrochemical industry, mining, and largest cities), together amounting to 85 percent of demand. Three new LNG export facilities were commissioned in eastern Australia in 2015 alone, with a nameplate capacity of 25 MTPA. Between 2015 and 2017, wholesale prices of natural gas increased threefold. Australian authorities reacted by introducing LNG export limits. They will be applied to companies selling the majority of natural gas to foreign customers whenever a shortage of natural gas for domestic customers is forecast. In the longer term, however, Australia will need to invest in the construction of pipelines linking the eastern part of the country to the western and northern regions, which hold more than two-thirds of all its natural gas reserves and which thus far have been focused on developing the capacity to ship it overseas. Infrastructure expansion will be all the more important in light of the likely increase in demand for natural gas. If Australia is to meet the 2015 commitment made in Paris to reduce CO2 emissions by 26–28 percent by 2030, it will have to limit the share of coal-fired power generation, currently at 63 percent.

A long-term assessment of the business case for LNG exports is somewhat challenging given the features of natural gas production from coal-bed methane (CBM) deposits. These deposits are the main source of supply for LNG liquefaction terminals in eastern Australia. By 2019, these facilities will represent almost 30 percent of Australia’s liquefaction capacity. CBM wells can be four times less productive than traditional (conventional) ones. Ensuring sufficient production therefore requires higher outlays for exploration and production. Local authorities expect that supplying 25 MTPA of LNG will require drilling as many as 1,000 new wells a year. Terminals in the west are supplied from off-shore deposits, where production is markedly costlier than onshore deposits.

Related: Falling Iraqi Oil Output Drags OPEC Production Down

The availability of resources for these investments will depend on global crude oil prices. Oil indexation still dominates as a pricing formula in long-term LNG contracts for East Asian customers. Spot contracts, while convenient tools for entering the market, do not offer LNG suppliers the sufficiently stable revenue perspective necessary to retrieve the investment made during the construction phase of the export terminals. The costs of Australian liquefaction facilities exceeded the initial expectations and took longer than anticipated to go online. The goal therefore is to ensure the highest possible rate of utilisation of this costly infrastructure.

Outlook

If Australia succeeds in overcoming the challenges facing its LNG industry and secures sufficient supplies of natural has for export, the result will be a strengthening of the most important market trend—the rise of liquefaction capacity exceeds the pace of growth in demand for LNG. Australian natural gas will keep making its way predominantly to East Asia—as much as 90 percent in 2019. Elsewhere, as in Europe, it will not be competitive vis-à-vis more affordable supplies of both pipeline and liquefied natural gas. Still, European customers will benefit from the greater availability of LNG, especially via spot deliveries. This trend will become even more prominent as the global fleet of LNG tankers grows. By 2022, the number of vessels will rise from the current 440 to 550, with new builds generally boasting larger capacity.

By 2019, natural gas might account for as much as 10 percent of all Australian exports. The rising prominence of the LNG industry in the Australian economy could translate into growing clout of LNG producers during the formulation of the country’s foreign policy. Together with other energy and mining sectors dependent on East Asian markets, the LNG industry is vitally interested in ensuring freedom and security of navigation, including in the South China Sea. Australia is therefore likely to speak in favour of diplomatic solutions to any territorial disputes in this region. At the same time, China is the largest recipient of Australian exports—32 percent, twice as much as the second-largest country, Japan, and five times more than South Korea. LNG shipments will only deepen this dependency, even if the majority of natural gas from Australia continues ending up in Japan. As a result, Australia may be reluctant to take a firmer stance in the event of a Chinese-driven escalation in the region, especially if ASEAN countries remain divided on the issue and the U.S. is politically and militarily disengaged.

By PISM.pl

More Top Reads From Oilprice.com:

[maywillow] 17/11/2017 22:45

Finance
Sovereign Funds Should Sell Off Oil Assets
Norway's setting a good example for Middle Eastern states with large rainy-day funds.
by Leonid Bershidsky
2
17 novembre 2017 à 18:26 UTC+1

Dusk. Photographer: Spencer Platt/Getty Images

It's easy to see the oil and gas asset sell-off proposed by Norges Bank Investment Management, the entity that runs Norway's $1 trillion sovereign wealth fund, as a bet on the hydrocarbon industry's long-term decline. Indeed, Siv Jensen, Norway's finance minister and the proposal's addressee, predicted such a decline in a conference speech on Friday. But there's a better reason for oil-based sovereign funds to change their thinking.

Economist Sony Kapoor, whose think tank, Re-Define, has long campaigned for the Norwegian Government Pension Fund's oil and gas divestment, laid it out in a report published in 2013:

Because the Fund gets new money from the sale of oil and gas every year, its final value (when the oil runs out) is very highly dependent on the price at which it is able to sell this oil. This means that the Fund has a large negative exposure to policy actions that need to be taken to tackle climate change. Any increase in the rise of the price of carbon emissions or restriction in their quantity will have a negative impact on the final value of the Fund. Despite this large exposure to carbon, the GPF continues to invest heavily in oil and gas majors, which account for three out of its ten largest investments.

Four years later, the fund's managers accepted the argument. In their letter to the finance ministry, they write that regardless of how hydrocarbon assets will perform in the future, the double exposure -- through the revenues that flow into the fund and through its investments -- increases the risk that the rainy-day fund is supposed to mitigate. They point out that, at 4 percent of the fund's value, its investments in oil and gas stocks are twice as high as an index-based approach would have allowed -- but these equities are far more sensitive to oil prices than the stock index.

The double exposure to oil fluctuations isn't limited to Norway. Of the world's 20 biggest sovereign-wealth funds, 11 are oil and gas-based. Their portfolios are generally not transparent, but research has shown that they've tended to overinvest in hydrocarbon-related stocks. A 2013 paper by Bernardo Bortolotti of Bocconi University in Milan and his collaborators put the share of total sovereign fund investment in oil and gas at 7.1 percent -- twice as much as financial investors from the same countries generally put in these industries. That share is roughly consistent with a 2010 paper by University of Michigan's Surendranath Jory and collaborators.

In 2008, University of Miami's Vidhi Chhaochharia and the International Monetary Fund's Luc Laeven wrote of an oil bias that was "particularly strong for SWFs from oil producing countries." "The fact that the home countries of some of the largest SWFs are major oil exporters could explain the relatively high share of investments in oil and related industries," the researchers wrote, suggesting that sovereign fund managers tend to invest in they understand best.

It doesn't really matter if one believes that oil is going out of fashion, as salt once did as a valuable commodity. The members of the Organization of the Petroleum Exporting Countries -- the United Arab Emirates, Kuwait, Saudi Arabia, Qatar, Iran, Libya -- have built up some of the biggest sovereign funds, don't think so. In its long-term outlook, published earlier this month, the organization predicts that by 2040, global oil demand will increase by 15.8 million barrels a day, implying an average growth of 0.7 percent a year. Though all the growth is predicted in the developing world -- demand is expected to fall in the rich nations -- that alone shouldn't be a reason to divest hydrocarbon assets. But investing in the industry that feeds the fund is not a good approach from a risk management point of view.

It's also a bad idea from a development standpoint. The sovereign funds have different stated goals -- from macroeconomic stabilization to funding pensions once oil runs out -- but it's always useful to see them also as vehicles for expanding a nation's horizons. Even if a fund invests overseas to prevent the Dutch disease, it's wise and forward-looking for it to invest in industries a country would like to develop at home. With investment comes access to technology and exposure to promising markets. Kapoor of Re-Define advised the Norwegian GPF to go overweight on sustainable energy to align the fund's activity to the Norwegian government's climate goals. Middle Eastern nations don't have to take this advice, but their efforts to diversify their economies could only benefit from diversifying their sovereign funds away from oil and gas.

This column does not necessarily reflect the opinion of the editorial board or Bloomberg LP and its owners.

To contact the author of this story:
Leonid Bershidsky at [e-mail]

To contact the editor responsible for this story:
Mike Nizza at [e-mail]
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[ariane] 16/11/2017 13:41

Dutch, German natural gas spot contracts rise on higher demand

London (Platts)--16 Nov 2017 816 am EST/1316 GMT

Dutch and German wholesale gas spot contracts rose Thursday morning on higher demand expected in both countries, with further dated contracts seen recovering some of the losses seen since Tuesday.

The TTF day-ahead contract was higher Thursday morning at Eur19.20/MWh, up 10 euro cent from the previous assessment, while the German GASPOOL equivalent traded much higher at Eur19.15/MWh, up 55 euro cent amid thin trading activity seen on the contract. The NetConnect spot contract was only up 5 euro cent at Eur19.45/MWh.

At around midday London time, Platts Analytics' Eclipse Energy forecast end-of-day consumption in the Netherlands to be 125 million cu m Friday, rising from 115.5 million cu m Thursday.

In Germany, consumption was forecast at 310.9 million cu m Thursday and higher Friday at 325.0 million cu m.

The short-term demand model is calculated from the latest demand, temperature and wind speed out-turns.

Norwegian gas flows into the Emden-Dornum receiving terminals fell Thursday morning to 113 million cu m/d from 119 million Wednesday morning, according to Norwegian gas pipeline operator Gassco.

Dutch gas production is expected to rise Thursday with nominations at 119.2 million cu m, compared with the 116.3 million cu m produced Wednesday, data from S&P Global Platts Analytics' Eclipse Energy revealed.

Storage net withdrawals decreased to 59.2 million cu m Thursday at 11:00 London time, down from 88.5 million cu m Wednesday at the same time, according to Eclipse Analytics data.

CustomWeather forecast temperatures in Amsterdam at 4 degrees Celsius above norms Thursday, moving higher to 3 C above norms Friday.

Berlin, in the GASPOOL area, was at 3 C above seasonal norms Thursday and Friday, while in Munich, in the NCG area, temperatures were expected to remain at 1 C below seasonal norms Thursday and Friday.

On the TTF curve, the December contract traded higher at Eur19.10/MWh, up 10 euro cent from Wednesday's close, while the equivalent GASPOOL contract was seen last trading higher at Eur18.90/MWh, up 17.5 euro cent.

The NCG December contract was not seen trading by midday but was also a touch higher with a bid-offer of Eur19.175-Eur19.20/MWh after it closed at Eur19.15/MWh Wednesday.