China’s natural gas demand is expected to reach 307 billion cubic meters (bcm) this year, an increase of just 10% from 2018, an official of state-run Sinopec Gas Co said on Tuesday, as a slowing economy hits consumption.
China is the world’s second largest importer of liquefied natural gas after Japan, producing 160.2 bcm of gas last year and importing 124.8 bcm, of which 74.3 bcm was LNG, with pipeline gas making up the rest.
Any demand increase is expected to boost its imports of the super-chilled fuel.
“Due to the macroeconomic situation and the government’s easing push to the coal-to-gas program, China’s gas consumption growth is slowing,” said the official, reading prepared remarks on behalf of Wu Gangqiang, the firm’s deputy chief economist.
“We expect the consumption growth for this year is around 10%,” he added. That figure compares with annual growth of 17% in 2018.
In its steady push to clear smoke-blanketed skies, China is forcing homes and industrial plants to cut use of coal, which fuels emissions of toxic sulfur dioxide and greenhouse gases, in favor of cleaner energy, such as renewables and natural gas.
China’s gas demand is expected to reach 510 bcm by 2030, led by city gas, industrial and gas-powered utilities, while demand from chemical plants is expected to decline, added the official.
City gas demand of 92.5 bcm in 2018 accounted for 33% of total demand, but there is another 10 to 15 years of rapid growth in demand ahead, as the trend of urbanization gathers pace, he said.
China’s industrial gas demand was 110.6 bcm, or nearly 40% of overall demand, he added. As China adopts stringent environmental measures, the company expects demand for industrial gas to become a vital driver of growth, he said.
Gas demand by utilities was 48.4 bcm, or about 17% of overall demand in 2018, with gas power capacity at 85.87 gigawatts (GW).
Still, high costs and decreasing subsidies from the government will limit demand from gas-powered utilities for electricity generation, he added.
China’s domestic production of natural gas is expected to reach 174 bcm to 175 bcm this year, with shale gas making up about 15 bcm, a research official from the Ministry of Natural Resources said.Shale gas output is expected to increase further over the next five or six years, said Pan Jiping, director of the strategic research center for oil and gas resources at the ministry.
China has been encouraging use of natural gas, as it is more efficient and cleaner than coal, which constitutes the bulk of its primary energy use, and aims to add another 4.93 million households to its coal-to-gas or electricity plan this winter.
Japan’s Inpex Corporation, with its joint venture partner Shell, has signed an amendment and extension to the Masela block production sharing contract (PSC) as well as an extension for the Abadi LNG project.
Inpex said last week that the amendment, signed through its Inpex Masela subsidiary, had included a seven-year additional time allocation and a 20-year extension for the Abadi LNG project with Indonesia’s upstream oil and gas regulator SKK Migas.
The amendment was signed in Jakarta in the presence of Ignasius Jonan, Minister for Energy and Mineral Resources of the Republic of Indonesia.
Inpex added that the signing had marked the execution of a formal agreement on the PSC terms previously agreed and announced as part of the approval of the Abadi LNG project’s revised plan of development by Indonesia’s government.
Abadi LNG project is the first large-scale integrated LNG development project operated by Inpex in Indonesia.
“The Abadi gas field features excellent reservoir productivity and contains significant resource volumes, raising expectations of efficient development and stable LNG production operations over the long-term,” the company stated.
Inpex also said that it would continue to work with its partner Shell to deliver an onshore LNG project as it prepares to start the front-end engineering design (FEED). Once completed the project is expected to produce approximately 9.5 million tons of LNG per year.
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New York (CNN Business) Elizabeth Warren doesn't just pose a threat to Wall Street. Her rising 2020 polling numbers are also striking fear in the heart of Big Oil.
Warren, currently the odds-on favorite to be the Democratic presidential nominee, wants to ban fracking "everywhere." And the Massachusetts senator pledged to immediately sign an executive order to stop all new offshore drilling leases. Both steps go further than her main rival, former Vice President Joe Biden.
It would be wildly bullish for crude oil prices. We'd be heading back to triple-digit prices very fast."
Warren's aggressive plan for fighting the climate crisis could have profound consequences for the oil and gas industry. Although an outright fracking ban seems unlikely to get through Congress and the courts, such a move would halt America's historic shale oil boom in its tracks, drive up gasoline prices, threaten good-paying jobs and make the nation more dependent on foreign oil.
"It would vaporize the oil and gas boom in the United States," said Bob McNally, president of Rapidan Energy Group, a consulting firm that advises energy companies and investors. "There is palpable concern in the oil and gas industry."
Wall Street analysts are already warning shareholders about the potential hit to the share prices of oil companies, which remain widely held in portfolios despite the climate crisis.
Pioneer Natural Resources PXD ExxonMobil XOM Chevron CVX "We think the greatest risk to energy companies would occur if Democratic candidate Elizabeth Warren wins," RBC Capital Markets wrote in a report published on Monday. The firm said it would be "very bearish" for a wide range of oil companies, including drillers such as, oilfield service firms and even integrated companies likeand
Warren's campaign declined to comment. But the candidate has defended her aggressive stance by arguing the world doesn't have the luxury of playing it safe.
"Taking bold action to confront the climate crisis is as important — and as urgent — as anything else the next president will face. We cannot wait," Warren wrote in a Medium post last month.
The best-case scenario for the oil industry could be the reelection of President Donald Trump, a climate skeptic who has actively supported the fossil fuel industry by slashing environmental regulations and promoting energy exports.
Democrats have taken a much more skeptical approach towards Big Oil than Trump as they pledge to tackle climate change. The leading candidates have called for ending fossil fuel subsidies
Besides Warren, Democratic presidential nominees Bernie Sanders, Kamala Harris and Cory Booker have also pushed to ban fracking , the controversial drilling technique that involves shooting water, sand and other compounds underground to release trapped oil and gas. Fracking has sparked concerns of contaminated drinking water, methane emissions and even earthquakes.
That's why environmental groups strongly support a fracking ban.
"A clean energy economy built to tackle the climate crisis cannot include fracked gas, which is a bridge to climate disaster," Ariel Hayes, national political director at the Sierra Club, said in a statement to CNN Business.
'Wildly bullish' for oil prices
Fracking, which gained popularity in the early 2000s, has made the United States the world's leading producer of natural gas and, more recently, the top oil producer . In 2016, fracking accounted for more than two-thirds of all oil and natural gas wells drilled in the United States, according to the Energy Information Administration
Driven by the shale revolution, US oil production has more than doubled over the past decade to about 12 million barrels per day. That surge of oil has cushioned the blow from recent events, including oil barrels sidelined by the attack on Saudi Aramco and US sanctions on Iran and Venezuela.
An outright fracking ban would probably send crude oil prices soaring because the United States produces more oil than any other country on the planet. The world is relying on US oil shale oil as the main source of growth for the next several years.
"It would be wildly bullish for crude oil prices. We'd be heading back to triple-digit prices very fast," said McNally, a former energy official under President George W. Bush.
Oil jobs at risk
But it wouldn't be bullish for the oil industry. That's because the fracking ban would probably cause highly leveraged US shale oil producers to go bankrupt, or at least have limited financial firepower to take advantage of high prices.
"They will have been regulated out of business," McNally said. "And the US oil companies that remain will get blamed for high oil prices."
A fracking ban could wipe out countless good-paying jobs in the oil and gas industry.
"You'd have layoffs, everything from the field hands up to the C-Suite," said Jeff Bush, president of oil and gas recruiting firm CSI Recruiting.
A 2017 study paid for by the American Petroleum Institute found that a fracking ban would cause the loss of nearly 6 million jobs and lift household energy spending by $4,500 a year.
Warren has pledged to create new jobs to help workers who are hurt by the transition to a greener economy.
Senator Elizabeth Warren has pledged to immediately put a stop to new fossil fuel leases for drilling offshore and on public lands.
"We will no longer force workers to make the impossible choice between fossil fuel industry jobs with superior wages and benefits and green economy jobs that pay far less," Warren wrote in the Medium post.
A fracking ban might not have a large impact on prices if oil demand weakened because of a rapid shift towards electric vehicles
However, most forecasters expect the world's appetite for oil will rise for many years, if not decades. And even Warren's own energy plan doesn't call for 100% zero emissions for new vehicles until 2030.
That means diminished domestic oil production would likely make America more dependent on foreign crude, undoing its strides toward energy independence.
"It's not going to reduce consumption," said Bush. "It just means we'd be buying more oil from overseas. I don't think anybody wants that."
An outright fracking ban also would require an act of Congress, according to analysts.
Such legislation would be unlikely to get through Congress because Republicans are widely expected to maintain control of the Senate. Even if the Senate flipped, moderate Democrats in oil-producing states such as Colorado and New Mexico would face pressure to oppose such a ban.
"There is no real clean path towards a fracking ban," said Josh Price, senior analyst at Height Capital Markets. "It seems completely unrealistic, close to impossible."
Federal drilling ban could slow oil boom
Still, Warren could take regulatory and executive actions aimed at discouraging fracking.
For instance, RBC said Warren would probably be able to ban fracking and all output on federal lands. Oil output on federal lands is about 2.7 million barrels per day, or 22% of total output.
If such a ban took effect in early 2021, it would slash US oil production by about 300,000 barrels per day that year, RBC said. And by 2025, the firm's US oil production forecast would decline by 1.2 million barrels per day.
The loss of US barrels would drive global oil prices $5 to $10 higher, lifting gasoline prices by 10 cents to 25 cents a gallon, according to RBC. And federal oil and gas revenue would tumble by up to $20 billion.
In sum, even though energy investors might respond negatively to a Warren victory, her proposed crackdown on Big Oil would face enormous challenges, from court fights and economic pressure to a potential political backlash.
"The market could overreact," RBC analysts wrote, "which may provide fundamental buying opportunities."
In other words, Warren's bark may be tougher than her bite, at least when it comes to oil.
Commentary: More of a good thing – is surplus renewable electricity an opportunity for early decarbonisation?
We are entering a world where renewables will make up an increasing share of our electricity supply –the electricity sector was the leading sector for energy investment in 2018, the third year in a row that this has occurred.
This trend is set to continue. In WEO 2018’s New Policies Scenario, 21% of global electricity production is projected to come from variable renewables by 2040, up from 7% in 2018, supported by about $5.3 trillion of investment. The EU share is even higher at around 39%. In our more ambitious Sustainable Development Scenario, which aims to get energy system emissions down to levels consistent with the Paris goals, variable renewables are projected to supply 38% of global electricity in 2040 (44% in the EU), a level that would require nearly $8.5 trillion of generation investment.
Regardless of scenario, this rapid expansion of renewables will inevitably lead to particular challenges to operating power systems. This is best highlighted by the so-called duck curve, made famous by the California ISO.
The curve was developed to show the impact of increasing distributed solar PV capacity on the demand for grid electricity. As solar PV capacity grows, the demand for grid electricity falls during the day with the greatest decrease in the middle of the day when PV production is highest – the belly of the duck. In the afternoon as PV production declines towards sunset, the demand for grid electricity can grow quite quickly – the neck of the duck.
The duck is growing faster than anticipated. Five years ago, the California ISO had expected California midday demand to drop over 40% on a sunny spring day by 2020 thanks to the growth of small solar PV systems. In fact, by 2018, the spring mid-day demand on the high voltage system had already decreased by two thirds. The consequent increase in supply required in the late afternoon as solar production recedes, was already close to 15 GW, significantly greater than the 2020 anticipated level of 13 GW.
The result is that some excess supply needs to be curtailed to balance the system. While the percentages of solar and wind production that have to be curtailed in California are rather small, in other jurisdictions the share is more significant.
In China, for example, the national average for wind curtailment was around 7% in 2018, with much higher levels in certain provinces. In the Canadian province of Ontario about one quarter of variable renewable generation in 2017 had to be curtailed, along with cuts in nuclear and hydropower output. This was in a jurisdiction where wholesale market prices were zero or negative almost one-third of that year.
The challenges are clear – a world with higher shares of variable renewable energy (VRE) – i.e., wind and solar PV – will face challenges with integration. This is a priority area of work for the IEA, and we are focused on providing insights on the issues and technologies that can be employed to deal with higher shares of variable renewables.
One of these insights is that renewables integration can be divided into a set of six phases dependent partly on the share of variable renewables in the system, but also on other system-dependent factors such as the share of storage hydro and interconnections.
Phase 1 - No relevant impact on system Phase 2 - Minor to moderate impact on system operation Phase 3 - VRE determines the operation pattern of the system Phase 4 - VRE makes up almost all generation in some periods Indonesia 0.1 Singapore 0.4 Korea 2.01 Slovak Republic 2.4 Norway 2.6 Switzerland 3 Thailand 3.12 Czech Republic 3.4 Hungary 3.8 South Africa 4.04 Mexico 4.8 New Zealand 4.9 Canada 5.1 Estonia 5.2 India 6 France 6.7 Japan 7.4 Poland 7.8 China 7.9 United States 8.3 Brazil 8.6 Finland 8.6 Turkey 9 Australia 9.6 Sweden 10.7 Austria 11.5 Morocco 11.7 Netherlands 12.1 Italy 13.9 Belgium 15.5 Greece 19.2 United Kingdom 21.1 Spain 21.5 Portugal 23.3 Germany 24.5 Ireland 27.6 Luxembourg 38 Denmark 49.5
Two countries have already reached Phase 4. Denmark, which has been a leader, has the significant advantage of strong interconnections to handle both surpluses and shortfalls. Ireland has much weaker interconnections and additional measures have been needed to ensure short-term system stability.
No country is yet in Phase 5 (where production can exceed demand) or in Phase 6, where seasonal storage solutions would be needed to match supply and demand.
Strong renewables policies are expected to continue to favour wind and solar power for the foreseeable future. This will mean that by 2030, we expect more countries, particularly in Europe, to evolve to these higher phases.
Too much of a good thing?
As more countries move to higher shares of VRE, it appears that there could be “too much of a good thing” – excess generation that may have to be curtailed and appears as wasteful.
The tendency is to treat this primarily as a technology problem for the power system to solve. Indeed part of the solution will lie in improvements in technology. We will need some form of energy storage to convert the excess at one time of day into necessary power system supply at another. Smart grids, especially smarter distribution systems, will be better able to manage increasing shares of renewables as well – and they too will likely have more energy storage. And finally, the growth of EVs (currently driving global battery demand) represents a huge potential source of storage and demand-side flexibility as well.
But treating this only as a technical problem is missing the economic perspective. Trillions of dollars of investment in renewables is expected in the coming years, and so there is a risk that billions of dollars of renewable electricity – zero marginal cost, zero carbon – could be wasted.
Economists have their own tools for solving these type of problems. Many would see not a problem but an opportunity – offering surplus electricity available at a zero (or low) price to customers during periods of surplus is a means to manage this surplus efficiently.
Dynamic pricing of wholesale electricity is often proposed as a mechanism to efficiently manage peak demand of electricity – to charge more when electricity is scarce. Not surprisingly, passing on high wholesale prices as high retail prices has been met with customer resistance, and the uptake of dynamic pricing has been rather limited.
However, if low wholesale prices were passed on as low retail prices, we would expect customers to be more accepting. While most small customers might not be expected to respond on their own, low dynamic prices create opportunities for innovators to develop technologies and processes that would make it easy and profitable for the customer to respond. Many of these will involve using the electricity to replace, at least in part, an energy service provided by fossil fuels. In this way, it can help hasten the decarbonisation goal of the clean energy transition.
Barriers to efficient pricing
Unfortunately for now, there are a range of barriers in our current policies that prevent electricity customers from seeing these prices: the level of electricity taxes, the design of electricity tariffs and more broadly our approach to the electricity demand side. This means there is a need to change outdated policies.
Much of our electricity policy dates from a period where wasteful consumption led to an increasing number of power plants – particularly fossil and nuclear plants. Indeed, electricity was considered to be a particularly inefficient means of achieving a level of energy service.
This has affected the way and level at which electricity is taxed, the way regulated prices are designed, and perhaps most challenging of all, how we address demand side policies and particularly electricity efficiency.
But now we are entering a different era, an era where most of the incremental electricity generation will come from wind and solar power. How should it change our taxation, rate setting and electricity efficiency policies?
Economics should guide us so that:
Taxes are fixed in an efficient way, in order to distort as least as possible consumers and producers decisions Consumption is efficient, both through taxes and regulated tariffs Ensuring end-use energy consumption is carbon-efficient
Electricity taxes that exist in many countries today were set as a result of either a deliberate policy to reduce electricity consumption in energy importing countries (Europe) and/or environmentally conscious jurisdictions (Europe, California). They have also provided an easily enforceable tax base for municipalities and subnational jurisdictions. These taxes can be quite substantial, amounting to over half the cost of power for households in some European countries.
Tax component Ex-tax Mexico 8.68 54.23 Turkey 20.36 83.5 Korea 13.31 97.14 Canada 11.52 101.48 Lithuania 38.77 92.64 Hungary 27.94 103.5 Norway 47.6 88.5 Estonia 42.25 116.31 Poland 37.73 134.4 Slovak Republic 30.01 150.06 Czech Republic 33.09 150.11 Slovenia 57.78 129.32 Latvia 61.66 126.59 Luxembourg 45.33 146.04 Greece 62.61 133.18 Sweden 75.54 120.45 Chile 31.45 165.53 Finland 65.14 134.04 New Zealand 26.21 174.75 France 72.59 129.78 Netherlands 54.22 156.67 Switzerland 38.68 173.33 United Kingdom 10.9 218.05 Austria 85.68 144.56 Japan 21.1 217.85 Australia 22.59 225.9 Ireland 30.55 226.26 Portugal 147.75 120.09 Italy 88.73 190.94 Spain 66.58 244.89 Belgium 103.11 225.55 Germany 190.6 162.69 Denmark 219.48 138.47
Yet many of the reasons for taxing electricity heavily are no longer valid. The emissions argument in particular makes little sense in highly decarbonised power sectors such as Sweden, France, or Switzerland.
In addition to taxation, pricing systems tend to discourage consumption regardless of how clean the production is. There are countries where, paradoxically, a high level of renewable penetration discourages the consumption of renewable energy.
Germany is probably the best known example. Although prices in the wholesale market can fall to zero when wind and solar power are particularly prolific, the end user cannot buy electricity at the real time price, but even if that were possible, it would mean paying the EEG payment (which is intended to recover the cost of renewables) which is currently 6.405 euro cents per kWh. This means that the end user incentive to use that renewable energy to substitute for fossil fuels in their own consumption is blunted.
What needs to be done instead is to encourage customer response based on the real-time price for power. Most other costs should no longer be recovered on a per kWh basis.
Getting prices right for the end consumer means also addressing regulated prices such as for networks where these are separately specified. Networks remain largely fixed cost entities in developed economies where demand has not been growing. For electricity customers, the value of the electricity network is as the provider of reliable electricity service – a value that is not directly related to the quantity of power delivered. Increasingly, as more and more customers generate their own electricity, the value of the network is evolving to become a platform to sell some of that power or other electricity services.
Moving towards a fixed charge would recognize the value of the network service for customers. It would also alleviate concerns that customers choosing to self-generate are not contributing sufficiently to the costs of using a network they still require.
Finally, demand-side policies should be designed in a way that minimizes both costs to consumers and their carbon footprint.
As renewables continue to grow and increasingly face curtailment, the optimal policy may no longer to be to encourage electricity conservation. Instead, demand side policies that encourage carbon conservation might be more efficient.
Marginal price minus average social marginal cost per kWh
The figure above shows how the prices charged for consuming an additional kWh of electricity in each US jurisdiction is compared to the social marginal cost of producing that electricity. Red means the social cost of production exceeds the marginal cost, suggesting that marginal prices are too low and interventions such as conservation programs could be efficient. Conversely, in the deep blue regions, electricity prices are too high, suggesting that conservation and net metering programs need to be reconsidered.
Ultimately, when marginal prices for clean electricity consumption are adjusted downwards the viability of electrification increases – which can replace other end-uses of fossil fuels.
In fact, these changing circumstances are beginning to be recognized. The California energy regulator, the California Public Utilities Commission, has recently ruled that utility energy efficiency programs can include those that encourage customers to substitute electricity for fossil fuels.
More of a good thing
The good news is that the direction for electricity investments is positive, with the share of renewables likely to grow rapidly spurred by government policies and falling costs. Yet the resultant growth of wind and solar power will lead to new integration challenges for today’s power systems and these challenges will become greater over time.
Yet solving those challenges will also lead to economic opportunities in the energy system – opportunities to reduce costs, waste and emissions by making electricity available in substitution of fossil fuels.
Policies are central to realising these opportunities, by reforming electricity taxation, getting regulated prices right, and emphasizing carbon conservation above electricity conservation. The right price signals will encourage the innovation needed to advance the clean energy transition. And in the end, customers will have more of a “good thing”: greater access to cheaper, clean power.
Source: Xinhua| 2019-10-12 23:15:44|Editor: huaxia
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Edward Yau, secretary for commerce and economic development of the Hong Kong Special Administrative Region government, speaks at a press conference in Hong Kong, south China, Oct. 10, 2019. (Xinhua)
A wide range of industries from retail to catering are embracing a chilly winter as the continued unrest has added huge pressure on the financial and trade hub that had already been grappling with the impact from a global economic downturn since last year.
HONG KONG, Oct. 12 (Xinhua) -- A slump in visitors to Hong Kong during the first week of October, normally dubbed as the Golden Week for tourists, came as the latest signal that an upheaval that has lasted since June is plunging the city into an economic abyss.
"Visitors to Hong Kong halved from a year earlier during the first week of October, and the employment in the tourism sector is worrying," said Edward Yau, secretary for commerce and economic development of the Hong Kong Special Administrative Region (HKSAR) government.
Tourism was not the only sector falling victim to violent incidents since June.
Analysts have pointed out that a wide range of industries from retail to catering are embracing a chilly winter as the continued unrest has added huge pressure on the financial and trade hub that had already been grappling with the impact from a global economic downturn since last year.
-- Hong Kong's exports fell 6.3 percent year on year in August, the 10th straight decline.
-- Retail sales tumbled 23 percent from a year ago in August, the sharpest monthly drop on record, marking a six-month losing streak.
-- The dropping of visitors has been widening since July and about 40 countries and regions have issued warnings concerning travel to Hong Kong.
-- An official index measuring the willingness to invest of small and medium-sized enterprises saw a steep drop in August to 32.1, the lowest reading since the index started to be published in 2011.
-- Private home prices had fallen for three months in a row till August, and the vacancy rate of office buildings rose to a five-year high.
Photo taken on Aug. 30, 2019 shows the discounted price of hotel rooms in popular spots of Hong Kong on online hotel reservation site Booking.com in Hong Kong, south China. (Xinhua)
"When exports, retail sales and even investment are weak, it is hard to be optimistic about the performance of the overall economy," Paul Chan, financial secretary of the HKSAR government said. "If the quarter-on-quarter growth rate turns negative again in the third quarter, Hong Kong's economy will fall into a technical recession."
Chan added that the market has already had a pretty clear idea about the current situation although the official figures have yet to be released.
Photo taken on Aug. 18, 2019 shows a drugstore near Tsim Sha Tsui of Hong Kong, south China. (Xinhua)
HKSAR government economist Andrew Au said shrinking consumption will also lead to a further drop in investment, contributing to even more feeble inner growth impetus.
Both the University of Hong Kong (HKU) and DBS Bank have predicted zero growth for Hong Kong this year in their respective reports, and rating agency S&P revised down Hong Kong's economic growth forecast for this year from 2.2 percent to 0.2 percent earlier this week.
Observers warned that the real challenge for Hong Kong will come when the jobless rate starts a hike.
Hong Kong's overall unemployment rate has inched up 0.1 percentage point to 2.9 percent, with the rate of retail, accommodation and catering up markedly to 4.6 percent. The HKU said in a report that the situation could continue to worsen and residents were much less confident in the job market.
Hong Kong is facing a more severe situation than any other previous crises including the SARS, HKSAR Chief Executive Carrie Lam said, stressing that the economy will be affected for a long time and the recovery will also be arduous.
A passenger takes the Star Ferry from Hong Kong Island to Tsim Sha Tsui in Hong Kong, south China, Aug. 18, 2019. (Xinhua)
The HKSAR government has carried out an array of pro-growth policies since mid-August, including a scheme worth 19.1 billion Hong Kong dollars (2.44 billion U.S. dollars) to relieve the burden on businesses and individuals amid the economic hardship.
Bolder moves could also be expected in policy address to be published soon, such as measures to increase the land supply and diversify the industrial structure.
Lam promised continued effort of the HKSAR government, but also stressed that to revive the economy and heal the split society, the foundation is the same -- the widespread violence must stop and Hong Kong shall no longer be harmed.
Vice Premier of the People's Republic of China Liu He shakes hands with US President Donald Trump (AFP Photo/Nicholas Kamm)
Washington (AFP) - US President Donald Trump on Friday announced a partial trade deal with China after talks in Washington with Vice Premier Liu He.
Here are the main points of the agreement, which has yet to be signed.
- A deal, in principle -
Trump said he hoped to have a deal signed with President Xi Jinping "in four weeks, five weeks, something like that."
The signing could take place in the middle of November in Chile on the sidelines of the Asia-Pacific Economic Cooperation (APEC) summit.
"We have a fundamental understanding on the key issues... but there is more work to do," Treasury Secretary Steven Mnuchin told reporters.
"We will not sign an agreement unless we get, and can tell the president, that this is on paper."
Mnuchin said Liu needed "to go back to do some work with his team, but we have made a lot of progress over the last two days," signaling that approval from the highest level in Beijing would be sought.
Previous apparent breakthroughs have faced opposition in Beijing and seen a resumption of the trade war.
- Agriculture -
China has pledged to rapidly increase purchases of US farm goods to $40-50 billion a year -- a sharp rise that would be more than double the level in 2017.
In 2017, before the trade war started, China imported $19.5 billion of US farm output, falling to just over $9 billion in 2018.
- Financial services and currencies -
"We've had good discussions with... the head of the People's Bank of China, their central bank," Mnuchin said Friday.
"We have also had extensive discussions on financial services opening up their markets to our financial services firms. So we have pretty much almost a complete agreement on both of those issues.
"Currency has been a very big concern... and we have an agreement around transparency into the foreign exchange markets and free markets, so we are very pleased with that."
The US Treasury in August branded China a currency manipulator, accusing Beijing of deliberately weakening the yuan to gain unfair trade advantages.
- Technology transfer -
Trump said the talks had "made very good progress on technology transfer" -- a key point of friction.
Without giving further details, he said an agreement could be reached soon, with US companies sharing their know-how in exchange for access to Chinese markets.
- Intellectual property -
"We have an agreement on intellectual property," the US president said, claiming another obstacle to an overall deal had been overcome.
- Settling disputes -
US chief negotiator Trade Representative Robert Lighthizer said a dispute settlement mechanism was being finalized.
The mechanism is seen as essential by the United States to enforcing any agreement.
Lighthizer said the next round of tariffs due to hit on December 15 could be canceled.
1. Three clear remarks by senior US officials in the past two months reveal some truths which the country’s governing body previously lacked the courage to accept and express.
2. After Yemeni Ansarullah’s drone attack on Aramco oil facilities in Saudi Arabia and in response to Saudi Kingdom’s pressure to confront the perpetrators of this attack, US officials clearly emphasized on not meeting the Saudi request and it was announced that it is the Saudi Arabia which has been attacked not the US.
3. Following consecutive political and military defeats in the region, the $8 Trillion costs of US military presence in the region came to light and it was announced that America’s presence in the Middle East has yielded no result and was a foolish act.
4. Recently and after Turkey’s aggression on northern Syria and the US’s turning its back on its Kurd allies, American officials admitted to having caused a bloody war in Iraq under the false pretext of weapons of mass destruction and stated that stepping into the trap of the Middle East was the worst decision America has ever made in history.
5. It seems that America’s governing body has reached this conclusion through actual experiences that the equation of power and political geometry in the world have changed, especially at its heart, the Middle East; and that the United States can no longer claim reign over the international system despite all its massive propaganda.
6. America has come to realize that it has only two ways to go; either it has to just be content with an empty mask of being a global superpower through bearing its great costs, or to take a realistic approach, acknowledge the present reality of the world, and free itself from enormous costs of this exposed show.
7. The US governing body has realized that today, for any reason, it has no superpower requirements and returning to the peak era is impossible and out of reach; its inability to execute strategic projects such as ‘partitioning the Middle East’, ‘Deal of the Century’, ‘regime change in Iran’, ‘instating Saudi Arabia as the regional police’, ‘Yemen war’, ‘Afghan peace’, and ‘Syrian crisis’ and etc. has been proved to all.
8. The US government's bitter but instructive admissions have led many West Asian nations, even those who have been preparing the grounds for and hosting America's presence in the region for years, to acknowledge that ‘the Middle East without America is a safer place’.
Translated by Mehr News Agency
MAH/IRN 83516262
An explosion has occurred at Saudi Aramco's 305,000 b/d joint venture company with Shell, the SASREF refinery, reports say, adding that the blaze was caused by a gas leak.
Two workers from the oil refinery have died, while two more were injured in the blast during maintenance work, Reuters reported citing the company's statement.
The statement says that the maintenance work will continue as planned.
There are contradicting reports about 18 people killed in the incident, though they have not been confirmed.
The SASREF refinery, a joint venture between Saudi Aramco and Royal Dutch Shell is located in Jubail on Saudi Arabia's eastern coast.
In April, Saudi Aramco reported that it would acquire SASREF (Saudi Aramco Shell Refinery) for over $630 million.
Oil prices extend fall on China, global demand concerns
https://finance.yahoo.com/news/oil-prices-pares-losses-reports-085100293.html
China said Tuesday there was "no difference" with the United States on reaching a trade agreement, amid scepticism over what US President Donald Trump has called a "substantial phase one" deal.
On Friday, Trump said after talks in Washington with Vice Premier Liu He that the two sides had reached an initial agreement, but while Beijing said progress
was made it never stated that a deal was struck at the meeting. Asked at a regular press conference on Tuesday if Washington and Beijing had the same approach on a deal, Chinese foreign ministry spokesman Geng Shuang said: "What the US has said is the actual situation, it is consistent with our understanding of the situation." Geng added: "Both sides are in consensus about the issue of reaching an economic and trade agreement, there is no difference." US Treasury Secretary Steven Mnuchin said Monday that US and Chinese officials will continue to hold talks by phone this week to finalise the deal. Trump said the agreement included a pledge by China to rapidly ramp up purchases of American farm products to $40-50 billion more than double the prior level of less than $20 billion in 2017. Geng said China "will also accelerate its purchases of US agricultural products". Chinese businesses have bought this year 20 million tonnes of soybeans, 700,000 tonnes of pork, 700,000 tonnes of sorghum, 230,000 tonnes of wheat, and 320,000 tonnes of cotton, he added. But few specifics are available on the deal announced by Trump, which would not roll back the tariffs already imposed on hundreds of billions of dollars in trade between the world's two dominant economic powers.
For his part, Liu said that "substantial progress" had been made in areas including agriculture, intellectual property rights protection and the transfer of technology, the official Xinhua news agency reported after the talks. The Chinese Communist Party mouthpiece People's Daily warned in an editorial Saturday the trade war would only be resolved by "abolishing all tariffs". China's cautious response to Trump's announcement has prompted scepticism over the progress of the deal. In turn, official media has hit back at reports doubting China's enthusiasm about the deal, with the state-run Global Times saying in an editorial that "the US and some Western media are looking for 'temperature differences' between Chinese and US announcements".
Canada’s election will determine its role on the global energy stage
By Kevin Orland and Natalie Obiko Pearson on 10/16/2019
CALGARY (Bloomberg) - At the Fish Place diner in Fort McMurray, booths are filled with oil workers in baseball caps and the parking lot is lined with pickup trucks sporting six-foot neon safety flags, a hallmark of the mining industry.
Fort McMurray is the regional hub for the oil sands that produce two-thirds of Canada’s crude, a status that puts the city carved out of Alberta’s wilderness at the heart of the Oct. 21 federal election.
Robbie Picard, who heads an oil-sands advocacy group, calls it “the most important election we’ve ever had.” Over a breakfast of eggs and cheese in the diner, Picard said that a second term for Prime Minister Justin Trudeau would cause “anxiety, depression and despair” in the city. “I’m terrified for our future,” he said.
In a campaign that’s been uncharacteristically personal in tone for Canada, energy and the environment is arguably the key policy area that will decide the election—and most agree the outcome of the vote will in turn be crucial for Canada’s energy sector.
Not only will it determine the future of carbon taxes, pipeline approvals and environmental regulations, it’s also a referendum on a dispute central to the country’s identity: Is Canada a global oil superpower or is it a leader in fighting climate change?
Trudeau and his Liberal supporters argue that it can be both, using proceeds from its oil and gas to fund green-energy solutions. He says he has supported the industry more than his Conservative predecessor, spending C$4.5 billion ($3.5 billion) to save a key pipeline project from cancellation, taking flak from the environmental camp in the process.
But critics including his main challenger, Conservative leader Andrew Scheer, hammer him for abandoning a pipeline through British Columbia, failing to push through another line to Canada’s east coast and passing a law that they say will make major energy projects impossible to approve. Trudeau’s comment at a town hall meeting in Ontario back in 2017 that the country needs to phase out the oil sands has added to the sense that it’s not just specific policies but the industry’s very existence that’s on the ballot.
“Do we want our energy industry to be a global player, or do we want our industry to go into hibernation and we’ll just slowly shut it down?” Derek Evans, chief executive officer of oil-sands producer MEG Energy Corp., said in an interview. “That’s the point we’re at.”
The source of the dilemma lies in the expanse of forests and marshes surrounding Fort McMurray. These lands contain the world’s third-largest crude reserves, but the sticky bitumen extracted needs to be transported to market, and that means building hugely contentious pipelines. At present, there just aren’t enough of them for an energy sector that accounts for a tenth of Canada’s economy and a fifth of its exports.
In recent years, rising production from the oil sands has strained against limited pipeline capacity, exacerbated by delays to projects like TC Energy Corp.’s Keystone XL. That has weighed on regional oil prices and prompted companies including Royal Dutch Shell Plc and ConocoPhillips to sell off Canadian assets in a $30 billion-plus capital exodus.
A year ago, the pipeline pinch reached crisis proportions, sending Canadian heavy crude prices crashing below $15/bbl and prompting Alberta’s government to intervene with mandated production cuts to stave off a full collapse. While prices have rebounded, the situation remains tenuous, hitting Alberta’s economy hard and inflaming opposition to Trudeau’s federal government.
The political predicament is encapsulated in the proposed expansion of the Trans Mountain pipeline, which carries the heavy crude extracted near Fort McMurray about 1,150 kilometers (715 miles) westward to a Pacific port near Vancouver.
In 2013, then-owner Kinder Morgan Inc. of Houston won federal approval to triple the line’s capacity, promising to alleviate the bottlenecks and help Canadian crude reach new markets in Asia. But the proposal hit so much opposition—legal challenges, protests and a British Columbia government pledging to block it—that by last year Kinder was ready to abandon it.
Then, in a move that stunned the nation, Trudeau’s government swept in to buy it, vowing it’d be built. Yet the purchase won Trudeau little support in deeply conservative Alberta, and it only hurt his standing with environmentalists, earning him the nickname “Justin Crudeau.” While opposition remains, construction on the project has begun.
Naomi Klein, the prominent Canadian writer and activist, said the purchase highlights the “utterly hypocritical” position Trudeau has taken since coming to power, allowing the oil sands to expand while claiming to make Canada a climate leader.
“What we need to be doing is investing the billions of dollars that the Trudeau government has been spending buying pipelines on rolling out renewable infrastructure,” she said in an interview. “We have not done that. We’ve wasted precious time.”
Trudeau’s energy policy thus risks alienating voters on both sides of a debate that is increasingly becoming a key dividing line across Canada. It’s a political reality that Scheer is playing upon, portraying his Conservative Party as a champion of the oil sector and pledging to remove the stricter environmental regulation brought in by Trudeau. With her party polling at a record, Green leader Elizabeth May also sees an opening.
Current polls suggest a close race, with Trudeau’s Liberals set to lose their majority. That raises the prospect of a minority Liberal government with the even more environmentally minded Green Party and New Democratic Party—“a nightmare” outcome for oil sands advocates like Picard, but arguably one in tune with voters in large parts of Canada.
May characterizes the election as a referendum on climate, representing Canada’s last chance to help fight global warming. “We can’t negotiate with the global atmosphere to say, ‘We need a bit more time,’” said May, whose campaign platform displays a photo of her being arrested protesting against the Trans Mountain pipeline.
That sentiment has traction across the country in Quebec, where about 500,000 people filled Montreal’s streets for a climate march led by Greta Thunberg last month. Environmentalist opposition from Quebec played a key role in TC Energy abandoning its Energy East pipeline, which would have crossed the province en route to Canada’s Atlantic Coast, displacing oil imports from the U.S. and allowing Canadian oil to be shipped to new markets like India.
British Columbia, Ontario and Quebec—which produces so much hydropower that it has to export some to the U.S.—have all invested heavily to reduce their greenhouse gas emissions, and Alberta shouldn’t get a “free pass” in cutting its own, said Karel Mayrand, director of the David Suzuki Foundation for Quebec and Atlantic Canada, a non-profit environmentalist organization.
“You could say ‘Alberta can export its oil, and Quebec can export its electricity and everyone shakes hands,’” Mayrand said. “But the problem is that for a growing share of the population, in Canada as well as in Quebec, accepting this means throwing all of Canada’s climate goals out of the window.”
Albertans meanwhile feel “extreme disappointment” that other provinces have blocked the pipelines that could help its industry, viewing it as an attack on their entire identity, said Rafi Tahmazian, a senior portfolio manager and energy expert for Canoe Financial in Calgary, Alberta’s largest city.
A minority Trudeau government with the Greens’ May and New Democratic Party leader Jagmeet Singh, both strident pipeline opponents, would create further pain for the industry and lead to turmoil in Alberta, including even increased talk about seceding from Canada, he said.
At the Trans Mountain terminus near Vancouver, the oil paradoxically arrives in a region banking on a post-carbon, tech-dominated economy. Businesses here pay North America’s highest emissions tax, electricity is generated almost entirely from hydropower, and all new vehicles will be zero-emission by 2040.
Legend has it that the sediments from the deep blue inlet at the Westridge Marine Terminal, the pipeline’s end, were molded to create the Ur-mother of the Tsleil-Waututh, an indigenous group that’s at the forefront of a legal battle against the expansion.
Expanding the pipeline as planned would mean a seven-fold increase in oil tankers navigating a narrow route through Vancouver’s increasingly congested harbour, and activists say it’s only a matter of time until a spill would occur. Local municipalities and the provincial government have joined First Nation groups in the legal challenge. Vancouver’s mayor was arrested protesting it last year alongside Green Party leader May.
It’s the sharp end of a dilemma over climate and energy that will confront whichever government emerges from the election.
“This battle will continue,” said Grand Chief Stewart Phillip, the president of the Union of B.C. Indian Chiefs. “It’ll continue until we finally declare victory.”
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FROM THE ARCHIVE ///
Footsie closed down 43.7 points at 7,167. Its midcap cousin, and the more UK focused index FTSE 250, shed around nine points
The LNG boom in the United States is helping households pay less for electricity, Energy Secretary Rick Perry told Fox News.
“We’re driving down the cost of electricity in most places in America,” he said. “[With the exception of] some places like New York that forbid natural gas pipelines from being built across their state," the Energy Secretary said, adding that New York currently had one of the highest costs of energy per kilowatt-hour.
“There are points in time where New Yorkers are having to look for different forms of energy and they’re going to old inefficient fuel-oil to drive that,” Perry also said, adding these alternatives were both more expensive and less environmentally friendly than LNG.
According to Perry, the U.S. domestic market is receiving about seven billion cu ft of LNG equivalent daily, and this will soon rise by another 3 billion cu ft after a terminal in Louisiana begins operating.
Indeed, natural gas has been steadily displacing coal in power generation plants. It has also been getting cheaper as production booms and demand lags behind even if it is growing strongly, too. On several occasions this year, natural gas prices in the Permian slipped below zero because of the amount of excess supply.
Related: Higher Oil Exports Insufficient To Cut Brimming Venezuelan Stocks
U.S. natural gas prices are trending lower because of this gap between supply and production, and this must have had an impact on utility bills in many parts of the United States.
On an average rate, there does not seem to be much difference in electricity bills in 2017 and this year. However, there are significant variations by state. For example, while in Idaho, the average rate per kWh is just $0.1058, in California it is $0.1990. Louisiana households pay $0.0937 per kWh but those in Massachusetts pay $0.2111 per kWh.
Cheap gas is certainly an important factor in bringing utility prices down. How far down it can bring them on its own, however, remains a question with as many answers as there are states.
By Irina Slav for Oilprice.com
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* China Sept crude oil throughput up 9.4% y/y at 56.49 million tonnes - stats bureau
* China Jan-Sept coke output up 6.3% y/y at 354.36 million tonnes - stats bureau
* China Sept coke output up 3.2% y/y at 39.22 million tonnes - stats bureau
* China Jan-Sept power generation up 3% y/y at 5.3 trillion kwh - stats bureau
* China Sept power generation up 4.7% y/y at 590.8 billion kwh - stats bureau
* China Jan-Sept non-ferrous output up 4.5% y/y at 43.47 million tonnes - stats bureau
* China Sept non-ferrous output up 5.1% y/y at 4.97 million tonnes - stats bureau
* China Jan-Sept crude steel output up 8.4% y/y at 747.82 million tonnes - stats bureau
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BP Plc, Chevron Corp and Royal Dutch Shell Plc are among the companies that will compete for exploration and production rights off the Brazilian coast on Thursday, in the first of three oil bidding rounds scheduled for coming weeks.
Combined, the minimum signing bonuses for the blocks in the so-called 16th post-salt oil bidding round in the Latin American oil powerhouse come to roughly $800 million.
That is significant by historical standards, but pales in comparison to Brazil’s so-called transfer-of-rights bidding round and 6th pre-salt round, both scheduled for early November. Those rounds are expected to bring around $25 billion and $2 billion into government coffers, respectively.
The post-salt blocks are less prolific than the pre-salt blocks, where billions of barrels of oil are trapped under a thick layer of salt beneath the ocean floor.
Still, there are some prized areas in the 16th round, particularly in the Campos and Santos Basins off the coast of Sao Paulo and Rio de Janeiro. One block in particular, the C-M-541 in the Campos Basin, has a minimum signing bonus of roughly 1.375 billion reais ($335 million) and directly borders the pre-salt region.
US says two fighter squadrons and additional missile defense batteries were being sent to Saudi Arabia. Photo: Photo: File
WASHINGTON: The Pentagon announced Friday it was bolstering US forces in Saudi Arabia after Riyadh asked for reinforcements following the September 14 drone-and-missile attack on Saudi oil plants which Washington blames on Iran.
Defense Secretary Mark Esper said that two fighter squadrons and additional missile defense batteries were being sent to Saudi Arabia, for a total of about 3,000 new troops from September this year.
The move comes as tensions jumped Friday after Tehran said that suspected missiles had struck an Iranian tanker in the Red Sea off the coast of Jeddah, Saudi Arabia, setting it on fire.
Tehran did not blame arch-rival Riyadh for the attack, and US defense officials said they were still looking into it and had no immediate explanation.
US: Tehran behind Sept 14 attack
Esper said he had spoken with Saudi Crown Prince Mohammad bin Salman Friday to discuss adding US firepower to the oil giant's defenses against Iranian attacks.
"It is clear that the Iranians are responsible for the recent attacks on Saudi Arabian oil facilities," he said.
"Despite Iran's attempts to deny their involvement, the evidence recovered so far proves that Tehran is responsible for these attacks."
The September 14 attack knocked out two major processing facilities of state oil giant Aramco in Khurais and Abqaiq, roughly halving Saudi Arabia's oil production.
Read also: Saudi oil attack: Evidence points to use of Iran weapons, says alliance
Washington condemned the attacks as a "act of war" but neither the Saudis nor the United States have undertaken overt retaliation.
But the incident added to tensions already soaring since early this year when Iran was accused of attaching mines to several tankers moored off Saudi Arabia and the United Arab Emirates, and then attacking or seizing others near the crucial Strait of Hormuz.
14,000 more US troops since May
Esper said that since May the United States has increased its 70,000-strong presence in the Middle East by 14,000 personnel, most of those deployed to the Gulf region in response to Iran's actions.
"The US military has on alert additional army, navy, marine and air force units to quickly provide increased capability in the region if necessary," he said Friday.
Read more: Iran tanker hit by suspected missile strikes near Saudi port
He also urged US allies in Europe to follow America's lead with their own defensive assets "for regional stability."
The deployments authorized Friday include two additional fighter squadrons, and supporting personnel, along with additional Patriot and THAAD missile defense batteries.
Tanker explosion mystery
The explosion on the Iranian tanker in the Red Sea Friday remained a mystery.
The National Iranian Tanker Company said the hull of the Sabiti was hit by two separate explosions off of Jeddah, saying they were "probably caused by missile strikes".
It initially blamed Saudi Arabia but then recanted the allegation, and no one claimed responsibility.
Oil prices surged about two percent on the news, which raised fresh concerns about a possible clash between the Iranians and Saudis.
"This clearly puts fuel on the Mideast fire," SEB commodities analyst Bjarne Schieldrop told AFP.
"After the attack on Saudi a few weeks ago... it's not a matter of if we get new comparable events — but when, and how much."
But Ayham Kamel of the Eurasia Group expressed caution, saying that ongoing efforts to deescalate tensions would not be halted.
He said that if not perpetrated by the Saudis, the attack could have been carried out by Israel seeking to disrupt Iran's oil exports, the country's key source of income, or from a terrorist group.
But he said both Tehran and Riyadh have shown interest in calming the situation.
"For now, the attack will likely not derail efforts to ease tensions in the region and it does not materially impact the possibility for an escalation between Iran and Saudi Arabia," he said.
Read more:
Venezuela’s state-run oil company PDVSA and China National Petroleum Corp have restarted crude blending operations at their Petrosinovensa joint venture this week, according to a document seen by Reuters and a source familiar with the matter.
Operations at the plant, located near eastern Venezuela’s Jose terminal, were halted last week because of an accumulation of crude stocks, people familiar with the matter said. Inventories have been rising due to U.S. sanctions on the OPEC-member nation, leaving few companies willing to buy Venezuelan crude.
The facility, which blends extra-heavy, tar-like crude from the Orinoco oil belt with lighter grades, produced 105,000 barrels of Merey crude on Tuesday, according to the document.
PDVSA did not respond to a request for comment.
It was the only blending facility operating. Petropiar, a joint venture between PDVSA and Chevron Corp, suspended blending operations in September as inventories rose. The company was repairing a gas leak and attempting to restart the facility, according to the document.
Venezuela reshuffled oil output in June to focus on producing Merey heavy crude, a blend of heavy and light oil most preferred by Asian refiners, hoping to secure exports. PDVSA lost its largest U.S. customers after Washington imposed sanctions in January.
Indian refiner Reliance Industries Ltd (RELI.NS) is scheduled to resume loading Venezuelan crude in October after a four-month pause, according to sources and internal documents from PDVSA seen by Reuters, a move that could help Venezuela’s state-run company drain its large oil inventories.
A Reliance representative said on Wednesday it has been supplying Venezuela with fuels permitted under U.S. sanctions, including diesel, and thus it “is able to recommence crude sourcing” in exchange for the refined products.
“These are actions compliant to U.S. sanctions as crude sourcing against supply of permitted products is allowed,” the representative said in a email to Reuters.
France’s Total SA (TOTF.PA), the big winner in a Brazilian auction of offshore oil concessions on Thursday, said it will not participate in a bigger auction scheduled for Nov. 6 of the so-called Transfer of Rights area in Brazil’s pre-salt region.
The company’s chief executive officer, Patrick Pouyanné, said in a statement that was because the competitive bidding rounds were for non-operating stakes.
The Brazilian government expects to raise 106 billion reais ($25.8 billion) from the auction that is due to attract major global oil companies.
A consortium led by Total won the exploration and production rights for an offshore block near the pre-salt region on Thursday, agreeing to pay the government a signing bonus of 4 billion reais ($978 million).
Total plans to expand its business in Brazil in the distribution of fuels, where it made initial inroads by buying Zema Petroleo in Minas Gerais State in November, the company’s vice president for the Americas, Jean-Michel Lavergne, said.
“Brazil is a very large market and joining the effort to supply gasoline to everyone in a safe, clean and cheap way is clearly one of Total’s strategic goals,” Lavergne said at an investment conference in Sao Paulo.
“So we started with the purchase of a network of stations in the state of Minas Gerais, so let’s see how this works out. We will continue to study opportunities in this area,” he said.
Commenting on plans by state-run oil company Petroleo Brasileiro SA (PETR4.SA) for the sale of refineries, Lavergne said the refining sector was “complex” and he was not sure whether such assets would interest Total.
Crude oil inventory levels aren’t the only thing in a constant state of flux at the crude storage hub in Cushing, OK. A year ago, we blogged extensively about Cushing’s major players, storage assets and incoming and outgoing pipelines, as well as plans for new pipes that highlight the hub’s continued significance, even in an increasingly Permian- and Gulf Coast-focused energy sector. A lot has changed since then, though. Some pipeline projects into and out of Cushing have advanced to final investment decisions (FIDs), while others have floundered or foundered. Also, brand-new pipeline projects have been announced, as was a big acquisition that will make Energy Transfer a major player in Cushing storage. Today, we begin a short series on recent developments at the Oklahoma oil hub and how they reflect changes in the ever-evolving U.S. energy markets.
In the first episode of our eight-part Oklahoma Swing blog series in the summer and fall of 2018, we said that Cushing, a small town in central Oklahoma, fully deserved its nickname: “Pipeline Crossroads of the World.” With 94 MMbbl of crude oil tankage, 3.7 MMb/d of incoming pipeline capacity and 3.1 MMb/d of outbound pipes, Cushing has long played a crucial role in (1) receiving crude oil from an array of production areas, (2) storing and blending crude, and (3) distributing oil to Midcontinent, Midwest and Gulf Coast refineries — and, more recently, to export docks for loading onto ships. As a testament to its market significance, Cushing for the past 36 years has served as the delivery point for the CME/NYMEX futures contract for benchmark West Texas Intermediate (WTI) crude. In Part 3 and Part 4 of the Cushing series, we reviewed the existing pipelines into and out of the Oklahoma hub, and in Part 6 and Part 7, we looked at projects to either expand the capacity of existing pipes or build new, greenfield pipelines.
Today, we turn our attention to what’s transpired since last fall on the Cushing-related midstream development front. We’ll start with a look at new inbound pipeline capacity to the hub. The biggest news here was the June 2019 decision by Phillips 66 and Bridger Pipeline to proceed with the construction of the 24-inch-diameter Liberty Pipeline (dashed orange line in Figure 1) from the Bakken to the Rockies to Cushing. The capacity of the new, $1.6 billion pipeline, which is backed by long-term shipper commitments, has not been announced, and will depend on the outcome of a supplemental open season the co-developers posted in July, but it will likely be at least 300 Mb/d and perhaps 400 Mb/d or more. The new pipe is scheduled to come online in the first quarter of 2021.
Figure 1. Crude Pipeline Projects Into Cushing. Source: RBN
Also, on August 29, 2019, the co-owners of the 190-Mb/d Saddlehorn part of the 340-Mb/d Saddlehorn/Grand Mesa Pipeline (pink line) from the Denver-Julesburg (D-J) Basin to Cushing committed to a 100-Mb/d Saddlehorn expansion. As its name suggests, Saddlehorn/Grand Mesa is a combination of two pipeline projects. Grand Mesa Pipeline Co., which is 100%-owned by NGL Energy Partners, controls 150 Mb/d of the pipeline’s capacity. Saddlehorn Pipeline Co., which controls the other 190 Mb/d, is co-owned by Magellan Midstream Partners and Plains All American, each with 40% stakes, and Western Midstream Partners, with 20%. As part of the agreement to expand the Saddlehorn portion of the pipeline to 290 Mb/d by late 2020, Noble Midstream Partners was granted an option to buy up to a 20% ownership interest in Saddlehorn, with Magellan and Plains each selling up to a 10% interest to Noble if the option is exercised.
Tallgrass Energy, in turn, continues to expand its Pony Express Pipeline (PXP; blue line) from Guernsey, WY, in the Powder River Basin to Cushing. This summer, Tallgrass completed a 20-Mb/d expansion of PXP that boosted the pipe’s capacity to 420 Mb/d; that followed a 50-Mb/d capacity bump-up that the company finished last fall. Tallgrass on October 1, 2019, initiated a binding open season for shipper commitments to support yet another expansion of PXP from origination points in Wyoming to Cushing. Our understanding is that the potential increase in capacity would be modest in size, perhaps 50 Mb/d to 100 Mb/d — again, if demand warrants. Separately, Pony Express’s owner this past Tuesday (October 8, 2019), initiated a binding open season for shipper commitments from Wyoming origination points to CHS Inc.’s 100-Mb/d refinery in McPherson, KS, which is located along PXP’s route. (CHS is a farmer- and rancher-owned cooperative that is also involved in propane marketing and ethanol production and trading.)
One other change to Cushing’s inbound pipeline capacity this year was on the White Cliffs Pipeline (red line), which runs from Platteville, CO, in the D-J Basin to Cushing and consists of two 12-inch-diameter pipes. One of the two pipes was taken out of crude oil service in May 2019, with a plan to convert that pipe to NGL service in December 2019. The switch reduced White Cliffs’ 215-Mb/d crude capacity by half, to 107 Mb/d. White Cliffs’ co-owners are SemGroup’s Rose Rock Midstream subsidiary (with a 51% stake), Plains All American (34%), Western Gas Partners (10%) and Noble Energy’s Samedan Pipe Line subsidiary (5%). (SemGroup announced on September 16, 2019, that it has agreed to be acquired by Energy Transfer for about $5 billion. More on that coming up.)
While the Liberty Pipeline is moving ahead and Pony Express continues to expand, plans for another, smaller pipe to Cushing appears to be on ice. Ergon Inc., which owns the general partner of Blueknight Energy Partners, and Alta Mesa Resources’ Kingfisher Midstream in May 2018 announced plans to build the 65-mile, 16-inch-diameter Cimarron Express Pipeline (short dashed green line) from the STACK play in Kingfisher County, OK, to Blueknight’s 6.6-MMbbl storage terminal at the Cushing hub. Construction of Cimarron Express had begun and the 90-Mb/d pipeline been scheduled to begin service in mid-2019, but in February 2019 Kingfisher Midstream told Ergon and Blueknight that due to a decline in expected production from Alta Mesa’s dedicated acreage in the STACK play, it had decided to suspend further investment in the project. Alta Mesa filed for Chapter 11 bankruptcy protection on September 12, 2019.
At least two other inbound pipeline projects to Cushing are still on the drawing board, with no commitments to build yet. For one, Tallgrass and Kinder Morgan so far have not pulled the trigger on their joint plan — announced in January 2019 — to provide 550 Mb/d of incremental takeaway capacity out of the Powder River and D-J basins to Cushing as soon as the second half of 2020. Under the plan, parts of Kinder Morgan’s existing Wyoming Interstate Co. (WIC; aqua line) and Cheyenne Plains (yellow line) natural gas pipelines between eastern Wyoming and south-central Kansas would be converted to crude service. Also, about 200 miles of new pipeline would be built from south-central Kansas to Cushing (dashed lavender line). Further, the plan calls for converting Tallgrass’s Pony Express from light-crude to heavy-crude service, with the heavy crude to come down from Western Canada.
And then there’s Enbridge’s prospective 250-Mb/d expansion of its 585-Mb/d Flanagan South Pipeline (purple line), which runs from Enbridge’s Flanagan crude oil terminal near Pontiac, IL, to Cushing and is part of the larger Western Gulf Coast Access System (WGCAS) that Enbridge developed to transport larger volumes of Western Canadian crude to the Texas Gulf Coast. Completed in 2014, Flanagan South was installed parallel to Enbridge’s 193-Mb/d Spearhead Pipeline (bright-green line), which also transports crude from the Flanagan terminal to Cushing.
That’s the latest on new crude oil pipeline capacity into the Oklahoma hub. In the next episode in this series, we’ll look at new storage capacity within Cushing, as well as Energy Transfer’s impending new role as a major Cushing storage player. We’ll also discuss Cushing’s outbound pipeline projects, a number of which have advanced to FID in recent
https://rbnenergy.com/that-was-then-this-is-now-an-update-on-cushing-related-crude-pipeline-projects
U.S. energy firms this week increased the number of oil rigs operating for the first time in eight weeks even though energy services firms are cutting jobs as most producers follow through on plans to reduce spending on new drilling this year.
Companies added two oil rigs in the week to Oct. 11, bringing the total count to 712, General Electric Co’s Baker Hughes energy services firm said in its closely followed report on Friday.
In the same week a year ago, there were 869 active rigs.
The oil rig count, an early indicator of future output, has declined over a record 10 months as independent exploration and production companies cut spending on new drilling as they focus more on earnings growth instead of increased output.
U.S. oilfield services firm Halliburton on Wednesday said it was cutting 650 jobs across Colorado, Wyoming, New Mexico and North Dakota amid slowing oil and gas activity.
Even though the number of rigs drilling new wells has declined since the start of the year, oil output has continued to increase in part because productivity of those remaining rigs - the amount of oil new wells produce per rig - has increased to record levels in most U.S. shale basins. [EIA/RIG]
The U.S. Energy Information Administration projected U.S. crude output will rise to 12.3 million barrels per day (bpd) in 2019 from a record 11.0 million bpd in 2018. [EIA/M]
U.S. crude futures, meanwhile, traded around $54 per barrel on Friday, up 2% after Iranian media said a state-owned oil tanker had been struck by missiles in the Red Sea near Saudi Arabia. The contract was on track for its first gain in three weeks. [O/R]
Looking ahead, U.S. crude futures were trading around $54 a barrel for the balance of 2019 and $53 in calendar 2020.
U.S. financial services firm Cowen & Co this week said that projections from the exploration and production (E&P) companies it tracks point to a 5% decline in capital expenditures for drilling and completions in 2019 versus 2018.
Cowen said independent producers expect to spend about 11% less in 2019, while major oil companies plan to spend about 16% more.
In total, Cowen said all of the E&P companies it tracks that have reported plan to spend about $80.5 billion in 2019 versus $84.6 billion in 2018.
Cowen said eight of the 47 E&Ps it tracks have reported spending estimates for 2020 with two increases and six decreases versus 2019.
Year-to-date, the total number of oil and gas rigs active in the United States has averaged 978. Most rigs produce both oil and gas.
The number of U.S. gas rigs, meanwhile, fell one to 143, the least since January 2017.
Analysts at Simmons & Co, energy specialists at U.S. investment bank Piper Jaffray, forecast the annual average combined oil and gas rig count will slide from a four-year high of 1,032 in 2018 to 951 in 2019 and 906 in 2020 before rising to 957 in 2021.
That is the same as Simmons forecasts since late September.
Washington — Venezuelan oil production, already averaging a historic low near 600,000 b/d, could quickly plummet below 300,000 b/d if the Trump administration allows a waiver for Chevron and four US oil services companies to expire next week, analysts told S&P Global Platts.
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"I think you'd see it go certainly to under 300,000 b/d within a month," said Neil Bhatiya, an associate fellow with the Center for a New American Security. "The question after that is whether and how fast there is backfilling by Chinese, or, more likely, Russian state firms. It will take a while though, so a Chevron-less Venezuela will probably be in the [sub-300,000 b/d] zone for the remainder of the calendar year."
At issue is a general license issued by the US Treasury Department on January 28 as the administration unveiled its most punitive sanctions on Venezuela's oil sector. The waiver allowed Chevron, Halliburton, Schlumberger, Baker Hughes, and Weatherford International to continue certain work with PDVSA, Venezuela's state oil company, while those sanctions were in place. The waiver, which was granted a 90-day extension in July, expires on October 25.
CAPITOL CRUDE PODCAST: Will Citgo's US refineries be seized by creditors?
A spokesman with Chevron said the company was still waiting for a decision on the waiver from the Trump administration. Spokesmen for the White House and Treasury did not respond to requests for comment.
Joe McMonigle, an analyst with Hedgeye Risk Management, said that the 90-day extension Treasury granted Chevron and other companies in July was likely the last and only extension for the waiver and served as more of a "wind-down period" for those US companies to prep their departure from Venezuela's oil sector.
Chevron "still prefers a waiver and most likely lobbying for it," McMonigle said. "But the reality is, the administration wants to ratchet up pressure and this is one of the few tools left in the toolbox."
Kevin Book, managing director with ClearView Energy Partners, said the Trump administration may increasingly oppose a waiver extension due to political sensitivities, particularly negative views voters may have of perceived leniency toward the Maduro regime. Any extension may require National Assembly leader Juan Guaido, who the US recognizes as Venezuela's legitimate president, to provide the administration "political cover" by publicly calling the Chevron extension a necessity for Venezuela's economy, Book said.
QUARTER OF RIGS
Andrew Stanley, an associate fellow with the Center for Strategic & International Studies, said about one quarter of Venezuela's active drilling rigs support joint-venture projects involving the US companies operating in Venezuela under the soon-to-expire waiver.
"If the waiver expires it will certainly have an impact on operations and production for PDVSA," Stanley said.
Chevron, a presence in Venezuela for nearly a century, currently works with PDVSA on four joint-venture operations in western and eastern Venezuela, including three heavy or extra-heavy crude oil projects, according to the company's website. Chevron's biggest project is Petropiar in the Orinoco Belt, which produces about 200,000 b/d, including an estimated 40,000 b/d by Chevron and 160,000 b/d by PDVSA.
Chevron's projects, however, are operating well below capacity, making up as little as 10% of the country's roughly 600,000 b/d output, according to Francisco Monaldi, the Latin American energy policy fellow at Rice University's Baker Institute for Public Policy.
Rosneft or a Chinese company may be willing to operate Petropiar if Chevron's waiver is allowed to expire, which could prevent oil output from falling more than 25,000 b/d to 50,000 b/d in the near term. But Venezuela's current constraint is sales, not production, Monaldi stressed.
UNABLE TO SELL
"They are unable to sell due to sanctions and their on-ground inventories are at capacity," Monaldi said, adding that floating inventory has reached record highs as tankers have become less available and more costly. "So given that situation they will have to close output regardless of what happens with Chevron unless the secondary sanctions enforcement eases."
Monaldi said he expects Venezuelan oil output to continue to decline through this year, even if the waiver is extended.
Earlier this year, S&P Global Platts Analytics forecast Venezuelan oil output to fall to 375,000 b/d by the end of next year, in its low-case scenario, under which Maduro retains power, the US imposes secondary sanctions similar to its Iran oil sanctions, and creditors accelerate their pursuit of PDVSA assets.
Stanley with CSIS said the biggest issue for the Venezuelan oil sector remains President Trump's August 5 order which placed a full economic embargo on the Maduro regime and served as a formal warning to Russia and China to end their financial support of the embattled government.
That order caused PDVSA's crude oil export to drop below 500,000 b/d in September, as buyers' fears of enforcement action from the US Treasury increased.
"This combined with refinery runs that continue to fall has seen storage levels at export facilities and upgraders build significantly, which is causing significant operational issues for PDVSA," Stanley said.
--Brian Scheid, brian.scheid@spglobal.com
--Edited by Alisdair Bowles, alisdair.bowles@spglobal.com
Tokyo — The majority of Japanese refineries are ready to supply 0.5% sulfur bunker fuels, well ahead of the International Maritime Organization's global sulfur mandate for marine fuels.
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The IMO will cap global sulfur content in marine fuels at 0.5% on January 1, down from the current 3.5%. This applies outside the designated emissions control areas, where the limit is already 0.1%.
Currently, IMO 2020 compliant bunker fuels still represent only a fraction of Japanese refiners' entire bunker fuel supply, but the proportion of cleaner fuels is expected to rise in the coming months as demand accelerates.
Low sulfur IMO 2020 compliant fuels are now available at 14 out of the 22 refineries, with three more refineries expected to be ready before year-end.
Japan's potential LSFO demand for bunkering is estimated to be around 100,000 b/d, according to S&P Global Platts calculations based on market information. This includes demand for domestic coastal vessels.
While Japanese refiners are ramping up LSFO production, they are still likely to maintain HSFO supplies to serve owners/operators installing scrubbers on their ships.
Japan has decided it will support the use of open-loop scrubbers aboard ships. Based on its environmental assessment, Japan will not ban discharge of washwater from open-loop scrubbers in its port waters, even though many ports worldwide have or are preparing to implement such bans.
INFRASTRUCTURE
JXTG
**JXTG Nippon Oil & Energy, the largest Japanese refiner, started supplying 0.5% sulfur bunker fuel oil from its six refineries in Japan as well as from an oil terminal in Niigata in the country's northwest as of October 1.
**JXTG's supply of 0.5% sulfur IMO-compliant bunker fuel oil is now available from its 145,000 b/d Sendai refinery in the northeast, 270,000 b/d Negishi refinery in Tokyo Bay; 135,000 b/d Sakai refinery, 320,200 b/d Mizushima refinery, 120,000 b/d Marifu refinery in the west; and its 136,000 b/d Oita refinery in the south west.
**The refiner also plans to start supplying IMO-compliant bunker fuels from its 197,100 b/d Kashima refinery in the east coast and its 129,000 b/d Chiba refinery in Tokyo Bay.
**JXTG's 0.5% sulfur bunker fuel oil is only available for ocean liners at its Sendai and Marifu refineries, with Kashima, Chiba, Negishi, Sakai, Mizushima and Oita refineries supplying IMO compliant fuel oil for both ocean liners and coastal vessels.
**In addition to the Niigata oil terminal, JXTG also plans to start supplying IMO-compliant bunker fuel oil at its five other oil terminals in Muroran in the north, Sakaiminato in the west, as well as Kitakyushu, Nagasaki and Kagoshima in the southwest. But all of its IMO-compliant bunker fuel supply is available only for coastal vessels at the six oil terminals.
Idemitsu Kosan
**Idemitsu Kosan, also on October 1, started supplying IMO-compliant bunker fuel oil from its 190,000 b/d Chiba refinery in Tokyo Bay, the 160,000 b/d Aichi refinery and 255,000 b/d Yokkaichi refinery in central Japan as well as at the 120,000 b/d Seibu refinery in western Japan.
**Japan's second largest refiner also started supplying IMO-compliant bunker fuel oil at its Tokuyama complex -- a former refinery, which currently supplies energy and chemical raw materials -- in western and southwestern Japan.
**The company plans to start supplying IMO-compliant bunker fuel oil a the 150,000 b/d Hokkaido refinery in northern Japan in December.
Fuji Oil
**Fuji Oil, in which Idemitsu Kosan holds a 6.57% stake, also started supplying 0.5% sulfur bunker fuel oil at its sole 143,000 b/d Sodegaura refinery in Tokyo Bay in October.
Cosmo Oil
**Cosmo Oil started its 0.5% sulfur bunker fuel oil supply as of October 1 at its 177,000 b/d Chiba refinery in Tokyo Bay, its 86,000 b/d Yokkaichi refinery in central Japan, and its 100,000 b/d Sakai refinery in western Japan.
TRADE FLOWS
**Japan's current demand for low sulfur bunker fuel oil comes mainly from major Japanese shipowners, who had secured term contracts.
**Mitsui & Co. Petroleum Ltd. supplied its maiden marine fuel 0.5% bunker of about 300-400 mt at Osaka/Kobe in western Japan in the week ended October 5, according to traders.
**Toyota Tsusho will be delivering its first low sulfur bunker fuel oil cargo of 600 mt for the Grand Mercury, a Toyota roll-on/roll-off ship, at Toyohashi in central Japan around October 21, following its purchase of the cargo from Idemitsu Kosan.
**JXTG and Cosmo Oil had suspended the supply of 1.0% sulfur A-fuel oil -- a blend of gasoil and fuel oil in a 90:10 ratio -- in the domestic rack and waterborne markets as of September 30 to shift their focus to supply IMO-compliant bunker fuels.
PRICES
**Reflecting Japan's growing preference for clean marine fuel, the spread between Japan delivered Marine Fuel 0.5% bunker and Mean of Platts Singapore Marine Fuel 0.5% averaged $136.46/mt month to date. In comparison, the premium for Japan Delivered Marine Fuel price marker averaged $76.30/mt in September, $71.14/mt in August and $38.39/mt in July.
**The spread between Japan delivered Marine Fuel 0.5% and 380 CST Fuel Oil hit a record high at $199.50/mt on October 8. The differential remained close to that level Thursday, assessed at a premium of $197.50/mt.
**Mitsui and Co. Petroleum Ltd. were the first to begin bidding for spot Marine Fuel 0.5% bunker during the Platts Market on Close assessment process. It submitted a bid for 800-900 mt of Marine Fuel 0.5% for delivery over October 18-20, at $587/mt on Thursday.
-- Takeo Kumagai, takeo.kumagai@spglobal.com
-- with Rason Chen, rason.chen@spglobal.com
-- Surabhi Sahu, surabhi.sahu@spglobal.com
-- Edited by Norazlina Jumaat, norazlina.jumaat@spglobal.com
Iran’s Rouhani vows response to oil tanker attack
By Arsalan Shahla and Golnar Motevalli on 10/14/2019
LONDON (Bloomberg) - President Hassan Rouhani vowed Monday that Iran would respond to an attack on one of its oil tankers in the Red Sea, saying the evidence suggested it was the work of a government not a terrorist group.
Addressing reporters in his first news conference since the U.S. abandoned the 2015 nuclear deal last year, Rouhani said officials in Tehran had seen footage of the incident and it was likely that several rockets were aimed at the tanker. He stopped short of assigning blame, but the vessel was sailing near the Saudi port of Jeddah at the time of the attack.
“This wasn’t a terrorist move, nor was it carried out by an individual. It was carried out by a government,” Rouhani said, adding that officials were also assessing rocket fragments.
The Gulf has seen a surge in tit-for-tat attacks on oil facilities, drones and shipping traffic since Donald Trump’s administration tightened sanctions on Iran’s oil exports earlier this year. The measures are part of Trump’s “maximum pressure” policy aimed at forcing Iran to curb its ballistic missile program and support for proxy militia around the Middle East, but have been met with defiance by the Iranian government, which has, instead, rolled back its own compliance with the nuclear accord.
Although all sides have said they want to avoid war, repeated incidents pose a growing risk to supplies from the world’s most important oil-producing region.
The attack on the Sabiti tanker came weeks after a drone strike on a major Saudi oil facility which the kingdom blamed on Iran. Iranian officials have said they weren’t involved in the attack, which rattled global oil markets, and was claimed by Iranian-backed Houthi rebels in Yemen.
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Neptune Energy acquires North Sea assets from Energean
10/14/2019
COURBVOIE, FRANCE - Neptune Energy has entered into a conditional Sale and Purchase Agreement with Energean Oil and Gas to acquire Edison E&P’s UK and Norwegian producing, development and exploration assets for an initial cash consideration of $250 million. The purchase is contingent on Energean completing its proposed acquisition of Edison E&P.
The portfolio will provide Neptune with material growth in contingent resources, an estimated 30 MMboe of 2P reserves and near-term production in core areas of the North Sea close to infrastructure. It includes:
Glengorm gas condensate discovery (25% WI) in the UK’s Central North Sea, close to Neptune’s operated Seagull project. Glengorm is an additional contingent resource.
Nova gas development project (15% WI) in the Norwegian North Sea: Nova is being developed as a subsea tie-back to the Neptune-operated Gjøa field. Production is expected from 2021, with estimated net 2P reserves of more than 11 MMboe.
Dvalin (10% WI) gas development project in the Norwegian North Sea: developed as a subsea tie-back to Heidrun, the four gas wells are expected to be drilled from the end of 2019, with first gas expected by the end of 2020. Net 2P reserves are estimated at more than 11 mmboe.
Scott (10.5% WI) & Telford (15.7% WI), Tors (68% WI), Wenlock (80% WI) and Markham (3.1% WI): combined incremental non-operated production of 3,000 boepd in 2019. Tors is strategically important to the Neptune-operated Cygnus field due to the shared export route.
Jim House, CEO of Neptune, said: “This is an important bolt-on acquisition that is in line with our strategy of consolidating our position in key areas with high quality and complementary assets.
“The assets are an excellent fit with our North Sea portfolio. Nova and Dvalin are expected to add 12,000 boepd to our production base over the next two years and Glengorm adds significant potential for the longer term.”
The transaction is subject to customary regulatory approvals, with completion expected early in 2020.
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FROM THE ARCHIVE ///
Nigeria, oil majors start talks to end $62 billion dispute
By Elisha Bala-Gbogbo on 10/14/2019
ABUJA (Bloomberg) - Nigeria began preliminary talks with international oil companies to settle a dispute over revenue.
The government, citing a 2018 Supreme Court ruling, says it’s entitled to $62 billion from the companies after they failed to comply with a 1993 law that hands the state a greater share of income when oil exceeds $20/bbl. The companies are challenging the claim.
“We have opened up a process of engagement between the parties,” Justice Minister Abubakar Malami said at his office in Abuja late on Saturday. “Whether those discussions will eventually translate to settlement, whether it will translate to opening up of a full-blown negotiation process, is what we wait to see.”
President Muhammadu Buhari is trying to bolster government funds after crude output and prices dropped. Nigeria relies on oil for at least two-thirds of state revenue and more than 90% of foreign-currency income. While oil is the country’s main export, it has also targeted other foreign companies in the past, fining mobile operator MTN Group Ltd. $5.2 billion in 2015, and eventually settling for less than $1 billion after months of negotiations.
Most of Nigeria’s crude is pumped by Royal Dutch Shell Plc, Exxon Mobil Corp., Chevron Corp., Total SA and Eni SpA, who operate joint ventures with state-owned Nigerian National Petroleum Corp. Under production-sharing legislation, the companies agreed to fund the development of deepwater oil fields on the basis that they would share profit with the government after recovering their costs. Crude was selling at $9.50/bbl when the law became effective 26 years ago, and is now trading above $60 in London.
Oil companies including Shell have gone to the Federal High Court to challenge the government’s claim that they owe the state any money, arguing that the Supreme Court ruling doesn’t allow the government to collect arrears. They also contend that because the companies weren’t party to the 2018 case, they shouldn’t be subject to the ruling.
“Taking into consideration the government’s need to attract investments, no possibility can be out-ruled,” Malami said. “The possibility of settlement is not out of sight.”
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FROM THE ARCHIVE ///
Oil short-selling more than doubles despite Mideast risks
By Carlos Caminada and Sheela Tobben on 10/14/2019
CALGARY (Bloomberg) - Oil short-selling has more than doubled in three weeks, with attacks on oil facilities and tankers unable to push prices higher for very long.
Hedge fund bets on a West Texas Intermediate crude rout jumped 47% in the week ended Oct. 8, following surges of more than 30% in the previous two, data released Friday show.
Futures in New York erased early gains on Friday following missile strikes on an Iranian tanker in the Red Sea, before climbing once again ahead of a partial trade deal between the U.S. and China. Oil closed 2.2% higher at $54.70/bbl. Crude has retraced all the gains made since the attack on Saudi Arabia’s giant Abqaiq oil-processing complex in mid-September.
“Investors are more worried about the global market and the poor outlook on demand,” said Stewart Glickman, an energy analyst at CFRA Research Inc. “I don’t think that one attack on a tanker in the Red Sea is enough to turn the tide.”
Aside from a few short-lived spikes, WTI has been stuck in the $50s since June as the U.S. keeps producing crude at a record pace. Meanwhile, the International Energy Agency on Friday trimmed forecasts for global oil demand growth this year and the next by 100,000 bpd.
The WTI net-bullish position -- the difference between wagers on a rally and bets on a rout -- shrank 30% to 94,875 futures and options, the U.S. Commodity Futures Trading Commission said. Long bets fell 3%. Shorts have surged 167% since mid-September.
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The Norwegian Petroleum Directorate (NPD) has granted Equinor a drilling permit for a well in the North Sea offshore Norway.
The well 35/11-23 will be drilled from the Deepsea Atlantic semi-submersible drilling rig. The well has been given the prospect name Echino Sør.
The drilling program for well 35/11-23 relates to the drilling of a wildcat well in production license 090.
Equinor received consent from the Petroleum Safety Authority (PSA) for exploration drilling in block 35/11 in the North Sea, using the Deepsea Atlantic rig, in September 2019. However, at first, the oil company did not receive consent for a sidetrack in exploration well 35/11-23.
The consent for the sidetrack was received later, in October 2019.
Equinor is the operator of production license 090 with an ownership interest of 45 percent. Other licensees are ExxonMobil Exploration and Production Norway (25 percent), Idemitsu Petroleum Norge (15 percent), and Neptune Energy Norge (15 percent).
The area in this license consists of a part of block 35/11. The well will be drilled about seven kilometres west of the Fram field.
Production license 090 was awarded on March 9, 1984 (8th licensing round on the Norwegian shelf). This is the 17th well to be drilled in the license.
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The Norwegian Petroleum Directorate (NPD) has granted MOL Norge, a Norwegian unit of the Hungarian oil company MOL, a drilling permit for well 25/8-19 S in the North Sea offshore Norway.
The NPD said on Monday that the well, which was given the name of Evra/Iving, would be drilled from the Deepsea Bergen drilling rig.
The drilling program for the well relates to the drilling of a wildcat well in production license 820 S. MOL Norge is the operator with an ownership interest of 40 percent. According to the NPD, this is the first well to be drilled in the license.
Other licensees are Lundin Norway, Wintershall Norge, and Pandion Energy with 30, 20, and 10 percent interest, respectively.
The area in this license consists of parts of blocks 25/7 and 25/8. The well will be drilled about six kilometers northwest of Ringhorne and 210 kilometers northwest of Stavanger.
Production license 820 S was awarded on February 5, 2016, in APA 2015 on the Norwegian shelf.
To remind, MOL has already received consent from the Petroleum Safety Authority (PSA) to use the Deepsea Bergen rig for the drilling of the 25/8-19 S well. The consent was given to the Hungarian operator in mid-September.
According to the consent from the PSA, the drilling operations were scheduled to begin on September 25 and expected to last 44 days.
As for the rig, Deepsea Bergen is a semi-submersible mobile drilling rig of the Aker H-3.2 type, built at Aker Verdal in 1983. It is owned and operated by Odfjell Drilling. The rig is classified by DNV GL and is registered in Norway.
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Saudi Arabia’s oil production will recover in October and November to levels above those seen before attacks on its energy installations in September, energy minister Prince Abdulaziz bin Salman said on Monday.
Production by the world’s largest oil exporter will reach 9.86 million barrels per day (bpd) in October and November, the minister said at a Russian-Saudi investment event in Riyadh.
Output fell by 660,000 bpd from August to 9.13 million bpd in the wake of the Sept. 14 attacks.
The attacks knocked out half of the kingdom’s oil production, or 5% of global output, sending oil prices soaring. But a quick recovery in production, coupled with concerns about slowing global economic growth, have reversed all those gains.
Prince Abdulaziz said Saudi Arabia’s production capacity would reach 12 million bpd by the end of November. Current exports stand at around 6.9 million bpd.
Saudi Arabia will continue with voluntary output cuts - part of a global deal by producers aimed at propping up prices - of around 400,000 bpd, he added
Compliance by OPEC and non-OPEC producers with the deal is seen at above 200% in September, sources familiar with the matter said on Monday.
The Saudi minister called for a focus on stability of the oil market, rather than prices.
OPEC members and allies, a grouping known as OPEC+, meet next in December to decide on output policy for 2020.
“We hope that Nigeria, Gabon, South Sudan and Iraq will be fully compliant with OPEC+ deal in October,” Prince Abdulaziz told reporters, referring to countries that have missed targets.
Speaking at the same event, Russian Energy Minister Alexander Novak said there were no talks underway to change the global output deal.
Moscow is fully committed to the deal, he added.
At an oil event in Kuwait City, Kuwaiti oil minister Khaled al-Fadhel said the prospect of talks about a deeper cut in production were “up in the air”.
An OPEC+ committee, known as the JMMC, will continue to monitor the oil market to see whether there is a need for a deeper cut or to continue at current levels, he said.
Any decision has to be taken by all members, he added.
There was a strong agreement between OPEC and non-OPEC producers to balance the market and that would continue, the Kuwaiti minister said.
The deal between OPEC, Russia and other non-OPEC producers aims to reduce output by 1.2 million bpd until March 2020 amid forecasts of excess supply next year.
Asia’s largest refiner Sinopec is considering cutting crude oil imports in December after global tanker freight rates surged and crimped its refining margins, three sources with knowledge of the matter said on Tuesday.
The refiner is studying how much volume and which long-distance cargoes it could cut among the cargoes due to arrive in China in December, one of the sources said.
Geopolitical risks drive unprecedented hike in oil tanker rates
By Olivia Konotey-Ahulu and Firat Kayakiran on 10/15/2019
LONDON (Bloomberg) - Nothing right now is stopping a surge in oil tanker rates that’s given owners of the vessels one of the biggest boosts in years.
Rates have rallied so high that a secondhand supertanker could theoretically pay for itself in a couple of voyages, according to estimates from Clarkson Platou Securities AS. A normal payback period would often be about a decade. The combined market value of Frontline Ltd. and Euronav NV -- two pureplay owners -- has gained by 78% to $4.8 billion since mid-August.
Multiple forces, most of them geopolitical, are driving the rally in vessel earnings that reached a record on Friday. Probably the most important bull factor was U.S. sanctions on two units of a Chinese shipping company in September, placing a part of its fleet of oil carriers off-limits for traders. That fired up a freight market that had already gained due to increased Middle East tensions this year.
“This is an exciting dynamic that could create the foundation for a steady improvement in rates and a sustainable period of out-sized cash generation,” said Robert Hvide Macleod, the chief executive officer of Frontline’s management company. “Given the geopolitical climate, we wouldn’t be surprised to see episodic periods where rates spike in the future as well.”
Daily rates for so-called very large crude carriers to ship oil to China from the Persian Gulf soared by 90% to $300,391 a day at the end of last week, according to data from the Baltic Exchange in London. Those same vessels, which can carry 2 MMbbl of crude, were earning $25,000 a day just a month ago.
The latest surge began in late September following the Trump administration’s sanctions on units of China COSCO Shipping Corp., the world’s largest merchant vessel owner. Traders were unclear about exactly which tankers were affected, making them wary of booking COSCO carriers even though only a unit was impacted.
Red Sea Incident. The latest lift came from another moment of tension in the Middle East. Iran said on Friday that missiles hit one of the country’s ships in the Red Sea. The incident comes less than a month after an unprecedented attack on Saudi Arabia’s oil industry, which prompted traders to rush for crude supplies from elsewhere.
Earnings for ships on the benchmark Persian Gulf-China route began to pass the $100,000-a-day mark -- already a very high level by historic standards -- early last week. On Friday, the VLCC Ardeche, was booked for a journey in early November from the Middle East to Singapore at a rate equating to $327,853, excluding idle days, according to a fixture report listed by shipping pool Tankers International.
New Thing. “It’s important to remember that rates were trending higher and well above our breakeven levels before the sanctions on COSCO added fuel to the fire,” Macleod said. “The fundamentals were in place due to U.S. exports, falling vessel deliveries, the highest refinery growth in 40 years, and healthy oil demand.”
In addition to that, hundreds of tankers are to be fitted with equipment to help them to meet International Maritime Organization sulfur-emissions rules that come into effect from January. Reports of some shippers shunning vessels that have called at Venezuelan ports in the past 12 months also played a part.
“Most people in the market haven’t seen this kind of market movement,” Jonathan Lee, chief executive officer at Tankers International, said of the rates rally. “It’s a unique situation but I think you’ve got to put this into perspective. What this is, is a cumulative effect of many things.”
The rush to secure vessels to ship oil in the market continues, according to Clarksons Platou.
“At current rates, owners could pay back a 10-year-old VLCC, valued at $47m including scrap value of $16m, after only two trips,” Clarksons Platou analysts including Frode Morkedal said in a research note Monday. “Even at half the current VLCC rate, most owners have an earnings yield of above 75% and could thus earn back their entire market cap within a year.”
Frontline, controlled by the Norwegian-born billionaire John Fredriksen, in August agreed to buy 10 Suezmax crude oil tankers built in 2019 from Trafigura Pte Ltd. for as much as $675 million in cash and shares.
There are some signs of oil-market stress from the surge in rates. Refining margins are being eroded, according to data from Oil Analytics Ltd. That means crude exporters will either need to discount their barrels to make it profitable for refineries to process them, or prices of fuel will need to climb.
Frontline’s Macleod says freight rates will settle in at significantly higher levels than seen earlier in the year as demand for vessels is exceeding supply.
“U.S. exports are leading to higher ton-mile demand, effective fleet supply will be reduced through the first half of next year as maintenance-driven off-hire increases,” he said. “And most importantly fleet growth will not be as dramatic as in years past.”
Related News ///
FROM THE ARCHIVE ///
The largest oil refiner in Asia and in China, Sinopec, is considering cutting refinery run rates as of November as soaring freight rates have eaten away at refining margins, people familiar with the plans told Bloomberg on Tuesday.
The global shipping industry has seen freight rates soar over the past few weeks as traders and shippers stay away from booking oil tankers owned by Chinese tanker companies that fell prey to U.S. sanctions for dealing with oil from Iran.
At the end of September, the U.S. imposed sanctions on several Chinese tanker owners for shipping Iranian oil, including units of Cosco, who owns more than 40 oil tankers, including 26 supertankers, or the so-called very large crude carriers (VLCCs).
The cost of chartering supertankers to carry crude oil from the Middle East to Asia soared by double digits overnight on the day following the announcement of sanctions as oil traders and shippers scrambled to understand the extent and impact of the U.S. sanctions.
Refining margins have yet to catch up with the surge in freight costs and currently, refiners are the ones that have to bear the higher shipping costs.
This dramatic increase in procurement costs for oil has led to Sinopec considering reducing refinery runs in November by one million tons, which would be equal to 5 percent of Sinopec’s refining output, one of Bloomberg’s sources said. Related: Buffett’s Big Bet On Energy
Some refiners in China and India have reduced spot oil purchases because of the surge in tanker rates, according to Bloomberg.
Sinopec is also considering cutting its oil imports for December, four sources familiar with the issue told Reuters on Tuesday.
“Refineries are facing strong pressure as spot premiums are high and freight rates have jumped, so it’s not economical to import crude,” one of the sources said.
Refiners in Asia may cut crude oil imports amid the high shipping costs, hurting overall demand, draining the oversupplied oil products market in the region.
By Tsvetana Paraskova for Oilprice.com
More Top Reads From Oillprice.com:
U.S. oil output from seven major shale formations is expected to rise 58,000 barrels per day in November to a record 8.971 million bpd, the U.S. Energy Information Administration said in a monthly forecast on Tuesday.
The largest formation, the Permian Basin of Texas and New Mexico, is expected to add 63,000 bpd to 4.547 million bpd, the tenth consecutive increase. Production declines are forecast in the Eagle Ford and Anadarko basins.
Even though the number of rigs drilling new wells in the Permian and Bakken has declined since the start of the year, output in both basins has increased as the productivity of those rigs reached record levels.
Oil production of new wells per rig has risen in most regions since the start of the year.
Separately, U.S. natural gas output was projected to increase to a record 84.0 billion cubic feet per day (bcfd) in November.
That would be up over 0.3 bcfd over the October forecast, putting production from the big shale basins up for a tenth month in a row even though the number of rigs in each region has declined since the start of the year.
Output in the Appalachia region, the biggest U.S. shale gas formation, was set to rise about 0.1 bcfd to a record 33.3 bcfd.
The EIA said producers drilled 1,184 wells, the least since February 2018, and completed 1,390 in the biggest shale basins in September, leaving total drilled but uncompleted (DUC) wells down 206 to 7,740, the lowest since November 2018.
That was the biggest monthly decline in DUCs on record, according to EIA data going back to December 2013.
Houston — Total volumes of US-origin crude exports are expected to see minimal impacts from spike in US Gulf Coast-loading VLCC freight rates of more than 128% since September 25, as a combination of geopolitical and pre-IMO 2020 factors reduced the VLCCs fleet capacity by 15%.
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Marginalized VLCC tonnage includes 42 COSCO units following US sanctions on two affiliates of COSCO Shipping Co. and 38 VLCCs owned by the National Iranian Tanker Company, an S&P Global Platts Analytics Spotlight report showed Monday. It also includes 24 VLCCs currently used for floating storage of low-sulfur bunkers or low-sulfur blending components to facilitate the switchover from 3.5% sulfur to 0.5% sulfur bunkers by January 2020, and 20 units currently dry docked for scrubber installations ahead of the IMO 2020 deadline.
Yet, the initial spark that fueled the pre-IMO 2020 storm were the US sanctions on tonnage of COSCO Shipping Tanker (Dalian) and COSCO Shipping Tanker (Dalian) Seaman & Ship Management Co., which sent the cost of taking VLCCs out of the USGC to unprecedented highs over the past two weeks.
S&P Global Platts on Tuesday assessed freight for the key VLCC 270,000 mt USGC-China route at lump sum $18 million, up 128% from September 25 -- the day before the sanctions news emerged -- after peaking at $21 million on Monday.
The arbitrage window for bringing US-origin crude into Asia Pacific markets remains adamantly shut since VLCC freight hit $20 million on October 11, Platts Analytics data showed. Arbitrage opportunities for other key crude grades such as West Africa-loading Bonny Light and Persian Gulf-loading Murban also remain firmly shut.
"If freight rates stay this high then US crude prices will have to fall," Sandy Fielden, Director, Oil Research, Morningstar Commodity Research, said last Thursday at the Crude Oil Quality Association conference in Dallas. "No one is going to buy crude that is more expensive than what is available in their immediate region. It's a world market and the only way for us to compete is through price."
The economics of taking US-origin crude will have to adjust to keep export barrels moving, likely leaving FOB prices to absorb the increase in freight, according to Platts Analytics.
"Likely you won't see traders coming to the market to take ships but the SK Energy, Oxy [Occidental], and HOB [Hyundai Oilbank] system guys will still need to take ships," a shipbroker said.
Volatility in the freight market has impacted most exported crudes around the world and the US grades are no exception. WTI FOB cargoes along the US Gulf Coast have plunged lower during the past week and were assessed Tuesday at a $2.83/b discount to the Dated Brent strip and a $2.40/b premium to the WTI NYMEX strip, which reflects a 15-45 day loading window. That is compared with the differential's high this year of WTI NYMEX strip plus $8.80/b, which was reached on May 28.
A majority of the exports that occurred last week were booked more than a month ago, when freight rates were much lower. New long-haul pipelines are bringing more light sweet crude from the Permian Basin to the US Gulf Coast and many of those barrels must be exported, which puts added pressure on the export market.
US crude oil exports rose by nearly 535,000 b/d for the week ended October 4, to reach over 3.4 million b/d, which was their highest level in about eight months, according to data released October 9 by the US Energy Information Administration.
Some crude traders expect to see some decline in US crude export volume as spot FOB cargoes are facing difficult pricing dynamics. However, delivered cargoes and contract deals will continue to keep exports flowing.
FREIGHT OUTLOOK
Industry participants are left questioning the sustainability of the rally, attempting to predict the day when market fundamentals will take a bearish turn. "It's going to take a while I think," a shipbroker said.
A cocktail of events have driven bullish sentiment in the VLCC market heading into the third quarter and the fourth quarter of 2019, including a reduction in fleet utilization in the spot market from Iran sanctions and IMO 2020 preparations as well as an overall uptick in crude exports moving out of the USGC on VLCCs.
Looking at the overall global VLCC fleet, which contains 792 ships worldwide, according to Platts Analytics, the combined events of the past year have led to a reduction of about 124 units or 15% of the fleet size available to the spot market, not counting the ships that could be affected by potential secondary sanctions on Venezuela.
The Forward Freight Agreement market would suggest rates for the USGC-China route to stay in the double digits at least moving into the next month, with the November contract for the 270,000 mt USGC-China route last traded at $44/mt, or a lump-sum equivalent of $11.88 million.
TRICKLE DOWN TO SUEZMAX AND AFRAMAX SEGMENTS
There is a possibility of an increased number of US-origin crude exports being diverted to Europe to avoid major costs on the typically Asia-destined VLCCs, however firming in the VLCC segments has begun to trickle down into smaller tonnaged ships.
The arbitrage for bringing WTI crude into Europe is open at 82 cents/b compared to UK origin Forties crude.
Long-haul Suezmax rates have reached rates seen by VLCCs less than two weeks ago, with the 130,000 mt USGC-Singapore route last assessed Tuesday at lump sum $9 million. On the trans-Atlantic front, rates have been slower to rise with the times as owners are more willing to make the shorter voyage to Europe, with anticipation of capitalizing on a bullish market instead of taking their ships out of the market for extended periods of time.
The cost of taking a Suezmax on a 145,000 mt USGC-UK Continent run was last assessed Tuesday at w180, or $32.18/mt, up 177% from the average rate for September.
--Catherine Wood, catherine.wood@spglobal.com
--Laura Huchzermeyer, laura.huchzermeyer@spglobal.com
--Barbara Troner, barbara.troner@spglobal.com
--Edited by Kshitiz Goliya, kshitizgoliya@spglobal.com
U.S. Gulf of Mexico crude oil production to continue to set records through 2020
By Corrina Ricker on 10/16/2019
WASHINGTON - U.S. crude oil production in the U.S. Federal Gulf of Mexico (GOM) averaged 1.8 MMbpd in 2018, setting a new annual record. The U.S. Energy Information Administration (EIA) expects oil production in the GOM to set new production records in 2019 and in 2020, even after accounting for shut-ins related to Hurricane Barry in July 2019 and including forecasted adjustments for hurricane-related shut-ins for the remainder of 2019 and for 2020.
Based on EIA’s latest Short-Term Energy Outlook’s expected production levels at new and existing fields, annual crude oil production in the GOM will increase to an average of 1.9 MMbpd in 2019 and 2.0 MMbpd in 2020. However, even with this level of growth, projected GOM crude oil production will account for a smaller share of the U.S. total. EIA expects the GOM to account for 15% of total U.S. crude oil production in 2019 and in 2020, compared with 23% of total U.S. crude oil production in 2011, as onshore production growth continues to outpace offshore production growth.
In 2019, crude oil production in the GOM fell from 1.9 MMbpd in June to 1.6 MMbpd in July because some production platforms were evacuated in anticipation of Hurricane Barry. This disruption was resolved relatively quickly, and no disruptions caused by Hurricane Barry remain. Although final data are not yet available, EIA estimates GOM crude oil production reached 2.0 MMbpd in August 2019.
Producers expect eight new projects to come online in 2019 and four more in 2020. EIA expects these projects to contribute about 44,000 bpd in 2019 and about 190,000 bpd in 2020 as projects ramp up production. Uncertainties in oil markets affect long-term planning and operations in the GOM, and the timelines of future projects may change accordingly.
Because of the amount of time needed to discover and develop large offshore projects, oil production in the GOM is less sensitive to short-term oil price movements than onshore production in the Lower 48 states. In 2015 and early 2016, decreasing profit margins and reduced expectations for a quick oil price recovery prompted many GOM operators to reconsider future exploration spending and to restructure or delay drilling rig contracts, causing average monthly rig counts to decline through 2018.
Crude oil price increases in 2017 and 2018 relative to lows in 2015 and 2016 have not yet had a significant effect on operations in the GOM, but they have the potential to contribute to increasing rig counts and field discoveries in the coming years. Unlike onshore operations, falling rig counts do not affect current production levels, but instead they affect the discovery of future fields and the start-up of new projects.
Related News ///
FROM THE ARCHIVE ///
Crude oil production from the seven major shale plays in the United States could hit 8.971 million bpd next month, growing by 58,000 barrels per day, the Energy Information Administration said in its latest Drilling Productivity Report.
Not surprisingly, the bulk of the increase will come from the Permian, where the EIA expects production to jump by 63,000 bpd in November. However, production in the Eagle Ford and the Anadarko play will decline by 12,000 bpd and 13,000 bpd, respectively, offsetting some of the gains.
The Permian will this month produce an estimated 4.547 million bpd of crude, far ahead of all the other shale plays. The Bakken ranks second in terms of production, at 1.477 million bpd, to rise to 1.488 million bpd in November. The Eagle Ford is third, with production averaging 1.378 million bpd this month.
At the same time, the EIA reported the number of drilled but uncompleted wells has been declining across the shale board. Drilled but uncompleted wells are a gauge of the industry’s readiness to boost production at short notice, which is important for traders’ peace of mind in times of heightened volatility. They also recently became the focus of criticism from industry insiders against the EIA, which, according to them, significantly overestimated the number of these wells.
In September, the EIA said, DUCs in the U.S. shale patch declined by 206 from August to 7,740. In the Permian, drilled but uncompleted wells last month totaled 3,668, down by 49 from August. This, according to historical EIA data, was the biggest drop in DUCs since 2013 when the agency started tracking these.
These are all aspects of a trend: the U.S. shale boom is slowing and capital is getting harder to secure, too. Banks have been reassessing the lending base for the oil and gas industry and the results may disappoint the latter amid persistent forecasts about slowing oil demand on a global scale. This, in turn, would mean a further slowdown in production growth.
By Irina Slav for Oilprice.com
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When OPEC and its allies meet in December to discuss their pact, they may have no other choice but to deepen the production cuts and possibly extend them beyond the current expiry date in March 2020.
Judging from last week’s monthly reports from the EIA, OPEC, and the International Energy Agency (IEA), the global oil demand growth picture has further dimmed, with all three organizations cutting their demand growth forecasts for this year.
With the expected recovery of Saudi oil production after the September 14 attacks on its oil infrastructure, oil stockpiles around the world are expected to add in the first half next year between 136 million barrels, as per OPEC figures, and 255 million barrels, as per the IEA, according to estimates from Bloomberg News’ Julian Lee.
So when they sit down at the summit in December, OPEC and its Russia-led non-OPEC partners may have to seriously consider deepening the cuts, barring another major supply disruption or unexpected optimism about oil demand growth in case trade disputes are resolved and economies pick up pace.
Last week, the EIA revised down its oil price forecast by $5 a barrel, due to the expected increase in global oil inventories in early 2020. In its Short-Term Energy Outlook (STEO) for October, EIA acknowledged there is a higher level of oil supply disruption risk than previously assumed, due to the attacks on Saudi oil infrastructure. Yet, EIA says, those risks are more than offset by “increasing uncertainty about economic and oil demand growth in the coming quarters, resulting in a lowered oil price forecast.” Related: Is The U.S. Gas Boom Already Over?
Then OPEC revised down its global oil demand growth estimate for this year, for a fourth time in five months, expecting demand to grow by just below 1 million bpd amid slowing economic growth momentum in the ongoing trade spats. In its closely-watched Monthly Oil Market Report, OPEC cut its world oil demand growth for 2019 by 40,000 bpd to 980,000 bpd, while leaving its 2020 demand growth estimate unchanged from last month at 1.08 million bpd.
The IEA on Friday cut again its demand growth forecast, to just 1 million bpd, on the back of faltering economies.
OPEC and Russia haven’t given yet early indications regarding the partners’ thinking about the December meeting. Russia’s Energy Minister Alexander Novak said last week that OPEC and its allies are currently not discussing changing the terms of their agreement, while OPEC Secretary-General Mohammad Barkindo is not ruling out the possibility of a deeper cut. All options are on the table, including a deeper cut from OPEC and its allies in December, Barkindo said last week.
By Tsvetana Paraskova for Oilprice.com
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Indian Nyara Energy has been buying Venezuelan crude oil from Rosneft and paying in fuel instead of cash to avoid a breach of U.S. sanctions against Caracas, Reuters reports, citing three unnamed sources claiming familiarity with the matter.
Nyara, which is an affiliate of Rosneft, delivered gasoil and gasoline to the Russian state giant, the sources also said.
Barter payments have emerged as the way to avoid sanction penalties as the sanctions only focus on cash, it appears. That is why Rosneft has not yet been sanctioned despite its continued partnership with PDVSA. As Reuters recalls, the latest round of sanctions that extends to non-U.S. business entities stated that oil as payment for loans was acceptable since it did not involve cash that would reach the Venezuelan government.
Exporting crude oil and getting refined products in return is another tactic Venezuela has been using since the United States began sanctioning it. This way, cash is not part of the transaction, but Caracas received fuel that it needs as local refineries struggle to operate at any meaningful rate following years of neglect and underinvestment, as well as the halt of diluent imports from the U.S. amid the sanction conflict.
Related: Is The U.S. Gas Boom Already Over?
Nyara Energy is not the only Indian company buying Venezuela oil from Rosneft. Heavyweight Reliance has also been importing Venezuelan crude from the Russian company after it announced a few months ago that it would suspend all direct dealings with PDVSA to please Washington. Now, however, Reliance has said it plans to restart direct purchases of Venezuelan crude from PDVSA. The way around the sanctions? Fuels for crude.
The continued, albeit indirect, crude exports to Indian companies seem to have helped PDVSA bring down inventories of crude that last month prompted a suspension in two blending facilities. Now, these have been restarted, too, and are producing crude for export once again.
By Irina Slav for Oilprice.com
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Brazil’s Senate passed the main text of a bill late on Tuesday defining the distribution of proceeds from a blockbuster auction of oil prospecting rights, a key milestone for the enormous offshore region known as TOR - the ‘transfer-of-rights’ area.
The bidders who win exploration and production rights in the massive Nov. 6 auction will be obliged to pay the government a combined signing bonus of some 106.5 billion reais ($25.8 billion), making it the largest oil bidding round in history, according to Brazilian authorities.
The fields are unique as Brazilian state-run oil firm Petroleo Brasileiro SA, better known as Petrobras, has already done significant exploration work in the area. As a result, it is already known to hold billions of barrels of untapped crude, reducing so-called exploratory risk.
Brazilian oil regulator ANP now estimates there are some 6 billion to 15 billion barrels of surplus oil in the TOR area, in addition to the original 5 billion barrels granted to Petrobras - a glittering prize for the world’s oil majors.
But the TOR auction is also unusually complex, presenting unique challenges for any potential bidder.
WHAT IS THE TOR AREA?
TOR is a roughly 2,800-square-km (1,080-square-mile) zone off the coast of southeastern Brazil, where billions of barrels of oil are trapped beneath a thick layer of salt under the ocean floor, according to surveys. It is part of a larger oil-producing zone known as the ‘pre-salt’, which has emerged as one of the world’s most promising conventional oil plays.
The area was defined in a 2010 deal between the government and Petrobras, when the giant company raised some $70 billion in the world’s largest-ever share offering at the time.
In order to maintain control of the company, the government granted Petrobras the rights to extract 5 billion barrels of oil in the TOR area in return for new shares worth 74.8 billion reais, or about $42.5 billion at that era’s exchange rate.
The deal was complicated by a provision that provided Petrobras and the government room to revise some terms when fields were declared commercially viable, taking into account shifts in oil prices, production costs and other variables.
Petrobras began declaring parts of the TOR area commercially viable in 2013 and haggled over contract terms with the government for the better part of six years, as oil prices swung sharply and studies showed larger reserves in the area.
Brazil’s cash-strapped government had not previously been able to offer that additional oil at auction because it had not come to terms with Petrobras on the revised TOR contract.
But those talks, which had long seemed stuck, accelerated after President Jair Bolsonaro took office in January, tapping a new economic team in his cabinet and a new chief executive officer for Petrobras. In April, the government agreed to pay Petrobras more than $9 billion to settle the dispute, and scheduled the TOR bidding round for October.
The auction was later delayed to Nov. 6.
HOW WILL THE AUCTION WORK?
The TOR area is divided into four zones: Buzios, Sepia, Atapu and Itapu.
The winners of those four areas will have to pay signing bonuses to the government of 68.2 billion reais, 22.9 billion reais, 13.7 billion reais and 1.77 billion reais, respectively.
While the signing bonuses are fixed, the fields will be awarded to the companies or consortia that offer the highest ‘profit oil’ — the percentage of oil from the respective zones that will go to PPSA, the state agency responsible for managing the oil delivered to the government.
The minimum offers for profit oil have been set at 23.24% for Buzios, 27.88% for Sepia, 26.23% for Atapu and 18.15% for Itapu.
Petrobras has already exercised its preferential rights to be the operator in Buzios and Itapu, so it will have at least a 30% stake in those zones.
But the company could also end up being the operator in Atapu and Sepia. Petrobras retains the rights to operate throughout the TOR area, given that it still has rights, under the 2010 deal, to extract 5 billion barrels from the zone.
To date, Buzios is the only part of the TOR area in which Petrobras is producing oil.
As a result, companies or consortia that present winning bids will need to come to a so-called ‘co-participation’ agreement with Petrobras in separate negotiations. The deadline for Petrobras and winning parties to strike those deals is 2021.
Separately, winning companies and consortia will be required to compensate Petrobras for exploratory and infrastructure work already done in the region. While there is no consensus estimate for how much that might add up to, it is widely believed to be at least several billion dollars.
WHO IS INTERESTED?
The November auction is expected to attract a range of major global oil companies, which have been discussing the opportunity with government officials in recent months.
Fourteen firms were approved to participate: BP PLC, Chevron Corp, China National Oil and Gas Exploration and Development Corp (CNODC), China National Offshore Oil Corp (CNOOC), Ecopetrol SA, Equinor ASA, Exxon Mobil Corp, Galp Energia SGPS SA, Petrobras, Petronas, Qatar Petroleum, Royal Dutch Shell PLC, Total SA and Wintershall Dea GmbH.
However, Total said last week that it was dropping out of the process. Galp and BP have said publicly that they believe the assets are getting expensive.
Ecopetrol, Qatar Petroleum and Wintershall are approved to participate only as non-operating members of consortia.
Nonetheless, the assets are seen as a prize given that they are guaranteed to hold massive amounts of oil. A push in Mexico under leftist President Andres Lopez Obrador to increase state control over the industry has also made Brazil the most sought-after conventional oil play in Latin America.
Not least among the interested parties is Petrobras itself. While the firm is aggressively cutting debt, CEO Roberto Castello Branco has said the $9 billion TOR payment from the government agreed last April would be used to participate in the auction.
Among the companies with exploration and production assets adjacent or relatively close to the TOR area - offering potential cost savings - are Shell, CNOOC and China National Petroleum Corp Ltd, the joint owner of CNODC with PetroChina Co Ltd.
Soaring oil-tanker costs are drying up activity in the U.S. export market as sellers are slow to lower offers and buyers are skittish, according to market participants.
Some sellers have held back from offering cargoes, while others have yet to reduce their offers enough to accommodate the rising cost of shipping oil, according to 10 market participants. Buyers are holding out for deeper discounts after sanctions on units of China’s COSCO Shipping Corp. took away tankers from the global shipping pool, they said. As a result, hardly any deals have been booked over the past few days, compared to six or seven seen in a typical day.
Benchmark rates surged to about $300,000 a day last week for shipments from the Persian Gulf to the Far East, while one supertanker was booked to carry oil from the U.S. Gulf to Asia for more than $15 million. Indian Oil Corp. said the rising costs force it to cut spot purchases. Shipments to Europe on smaller tankers have increased in the first half of the month as rates for larger vessels skyrocketed, according to Vortexa Ltd.
The increased shipments to Europe may tail off as the impact of attacks last month on Saudi oil infrastructure fades, said Stefanos Kazantzis, McQuilling Services LLC‘s senior adviser for shipping and finance. “We are not seeing yet the same volumes fixed for second half October as we did for first half for U.S. crude shipments to Europe.”
U.S. sellers have the option of selling to domestic refiners who can still absorb the local shale, so there isn’t pressure to sell their cargoes overseas, said according to Andy Lipow, president of Lipow Oil Associates LLC in Houston. American sellers also have the opportunity to store the barrels in abundant onshore tanks, he said, noting that storage can be obtained as cheaply as $0.50 to $0.60/bbl per month.
Gulf Coast crude stockpiles were 221.4 MMbbl as of Oct. 9, about 61% of the 365.4 million total working capacity at refineries and tank farms, according to the U.S. Energy Information Administration.
While few trades are getting done, price assessments are starting to slip. Waterborne prices for West Texas Intermediate crude were $2.83/bbl below Brent futures on the Intercontinental Europe Exchange Monday, from a $1.48 discount on Oct. 7, according to Argus Media.
Port Slowdown. Some businesses associated with exports, such as volume-measuring and quality-testing, have also seen a decline because fewer trades are getting done. For one U.S.-based company, activity is down some 10% from the same period last year, said a person familiar with the matter.
Corpus Christi, Texas, where oil exports grew to more than 685,000 bpd in August from 553,000 in January, is expecting slower growth because of the freight costs.
“The Port of Corpus Christi is preparing for a slower U.S. crude export growth rate from its site in November because of the surge in freight rates from the Cosco sanctions,“ said Sean Strawbridge, the chief executive officer of the Port of Corpus Christi.
https://www.worldoil.com/news/2019/10/16/us-crude-exports-drying-up-as-tanker-rates-skyrocket
The American Petroleum Institute reported late Wednesday that U.S. crude supplies rose by 10.5 million barrels for the week ended Oct. 11, according to sources. The API report, which was released a day later than usual because of Monday's Columbus Day holiday, also reportedly showed stockpile declines of 934,000 barrels for gasoline and 2.9 million barrels for distillates.
Inventory data from the Energy Information Administration will be released Thursday. The EIA data are expected to show crude inventories up by 4 million barrels last week, according to analysts polled by S&P Global Platts. They also forecast supply declines of nearly 1.8 million barrels for gasoline and 2.6 million barrels for distillates.
LAGOS: Nigeria is looking to claim $62 billion from international oil firms for back revenues it says it is owed — but even the country’s own oil minister admits the government has little chance of success.
The eye-watering amount relates to a 1993 law governing production sharing agreements between the country and oil majors that said the revenue split should be reviewed if prices reached over $20 per barrel.
Despite the price of crude soaring above that point over the past two decades the division of spoils was never recalculated — and Africa’s biggest oil producer insists the time has come to pay up.
In October 2018, three oil-rich states in southern Nigeria won a court ruling obliging the central government to up its share of the revenues from the lucrative offshore fields.
When the law governing production-sharing contracts came into effect 26 years ago, foreign oil majors agreed to pay about 20 per cent of revenues from deep offshore facilities to the government.
The authorities say that means they are owed funds — and have come up with figure.
“We are demanding $62bn from oil companies,” Nigeria’s Attorney General Abubakar Malami confirmed to AFP.
‘No basis’
But the details of the claim remain sketchy and the way forward unclear.
Oil executives insist the companies are not liable for any back payments.
AFP has learnt that at least five cases are before the Nigerian high court challenging the claim.
Some of the world’s biggest energy companies — Shell, Exxon Mobil, Chevron Eni, Total and CNOOC — extract most of the crude oil in Nigeria. “These demands have no basis,” a representative of one of the major oil firms told AFP on condition of anonymity.
“We have no idea how the government arrived at such an amount, it has not told us.” The executive said the companies were not involved in the case between the oil-producing regions and the government that resulted in the 2018 ruling.
Published in Dawn, October 17th, 2019
The oil auctions in Brazil could help cut Brazil’s deficit for this year to below US$24 billion (100 billion Brazilian reais), the Secretary of the Treasury, Mansueto Almeida, said on Thursday.
The government expects the transfer-of-rights auction on November 6 to fetch as much as US$11.56 billion (48 billion reais), Almeida told local television channel GloboNews, as carried by Reuters.
This month and next, Brazil is holding three oil auctions for different areas under different regimes in its offshore basins.
The first auction, held on October 10, attracted major international oil companies, with Big Oil scooping up exploration blocks in the bid round that fetched a record total amount of signing bonuses. Total, Shell, BP, ExxonMobil, Chevron, Petrobras, Petronas and Repsol all won oil exploration blocks in the concession bid round.
After winning an exploration license in the auction, Total confirmed last week that it would not participate in the upcoming Transfer-of-Rights (TOR) Surplus Round on November 6, because the competitive tender is only offering non-operated interests.
In the 6th production sharing round, to be held on November 7, Brazil’s oil regulator said this week it had approved the participation of 17 companies in the bidding, including BP, Chevron, Equinor, ExxonMobil, Petrobras, Repsol, and Shell. The number of participating companies is a record for this kind of oil auction in Brazil, the regulator said.
Related: $300 Oil: What If The Attacks In Saudi Arabia Had Destroyed Production?
Brazilian Mines and Energy Minister Bento Albuquerque said that the positive first auction last week signals that the other two bidding rounds would also be successful.
Commenting on the bid round from last week, Juliana Miguez at Wood Mackenzie’s Latin America upstream said that frontier acreage failed to attract interest, with majors focused instead on just the Santos and Campos basins.
“The Majors and Petrobras look to be keeping their powder dry, preferring to wait for the two upcoming rounds,” Miguez added.
By Tsvetana Paraskova for Oilprice.com
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The Venezuelan government is readying to hand over control over state oil company PDVSA to Russia’s Rosneft, a local newspaper has reported, citing sources from the industry.
Russian TASS reports, quoting El Nacional, that the radical move is being discussed as a way of erasing Caracas’ debt to Moscow. The debt is sizeable: at the end of June this year, money owed to Rosneft alone stood at $1.1 billion. That’s down from $1.8 billion at end-March.
Two years ago, Caracas and Moscow sealed a deal for the restructuring of another $3.15 billion debt to Russia over 10 years with minimum payments over the first six years. Since 2006, Russian loans to Venezuela have reached more than $17 billion in total.
According to the El Nacional report, Moscow had reacted positively to the suggestion, and several commissions had been set up and sent to Venezuela to evaluate the situation at PDVSA. The first feedback from these commissions was reportedly that the company was too large and it needed serious layoffs to become more competitive.
Related: Is This The End Of The Lithium-Ion Battery?
Competitiveness remains questionable, however. Most of the U.S. sanctions on Venezuela have targeted precisely PDVSA because of its vital role as the country’s—and the Maduro government’s—cash cow. Rosneft is the subject of U.S. sanctions, too.
Rosneft is active in Venezuela in joint projects with PDVSA. However, these activities appear to not be in breach of U.S. sanctions, according to the U.S. Special Envoy for Venezuela Elliott Abrams. However, Abrams said last month that sanctions may be coming for the Russian company in the future. If the El Nacional report is confirmed, these will likely come sooner rather than later
Caracas reportedly wants to hand control over to Rosneft without having to go through privatization. In any case, a change of ownership over PDVSA would need to be approved by the National Assembly, which is controlled by the opposition.
By Irina Slav for Oilprice.com
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Record Gulf oil output to average 2 million barrels daily in 2020
Shell's largest floating platform in the Gulf of Mexico, the Appomattox, trekked from Ingleside in May 2018 to its location 80 miles off the southeastern coast of Louisiana. The platform is expected to start producing oil this fall. less Shell's largest floating platform in the Gulf of Mexico, the Appomattox, trekked from Ingleside in May 2018 to its location 80 miles off the southeastern coast of Louisiana. The platform is expected to start ... more Photo: Shell Oil Photo: Shell Oil Image 1 of / 1 Caption Close Record Gulf oil output to average 2 million barrels daily in 2020 1 / 1 Back to Gallery
The Gulf of Mexico is churning out oil at record highs each year and will average 2 million barrels per day in 2020 for the first time, the federal government said.
As new projects come online, the Gulf already has averaged record highs in 2018 and now in 2019 - even with temporary outages from hurricanes and tropical storms - and despite dwindling exploration and drilling activity in the deepwater Gulf.
The U.S. Energy Department said Gulf crude output was 1.8 million barrels daily in 2018 - a new record - and that production entered this year at 1.91 million barrels daily as Royal Dutch Shell, Chevron and others brought new platforms into production.
Current production is estimated at or just a shade below 2 million barrels daily. But the 2019 average will be closer to 1.9 million barrels because of storm outages that dipped production volumes at times, the Energy Department said.
However, even with the offshore growth, the Gulf will account for a smaller percentage of total U.S. oil output than before because onshore shale oil growth has risen at a faster pace.
RELATED: As energy world focuses on Permian, the Gulf makes its own comeback
In 2011, the Gulf made up 23 percent of total U.S. crude production. Next year, even at 2 million barrels a day, the Gulf will only account for 15 percent, according to the Energy Department.
After all, West Texas' booming Permian Basin alone is currently churning out 4.6 million barrels of oil daily as the world's largest oilfield.
Apart from Shell and Chevron, other companies are bringing on new Gulf projects this year and next, including BP, Occidental Petroleum of Houston, Talos Energy of Houston, Fieldwood Energy of Houston, W&T Offshore of Houston, LLOG Exploration of Louisiana and Murphy Oil of Arkansas.
Eight projects were slated for completion this year with four more in 2020.
However, drilling and exploration activities in the Gulf are at some of their lowest levels since the 2010 Deepwater Horizon tragedy triggered a temporary moratorium. Instead, many companies have focused on cheaper expansion projects in the Gulf rather than push forward with multibillion-dollar new platform projects.
Russia, the world’s No. 2 oil producer, has become an unintended beneficiary of U.S. sanctions after an embargo on Chinese ships drove up tanker freight rates, spurring record premiums for Russian crude that takes just days to arrive in North Asia.
Demand for key Russian oil grades sold in Asia has been strong in the past month after an attack on key oil processing facilities in Saudi Arabia drove up prices for spot crude while Asian refiners are processing more low-sulphur grades to meet shippers’ demand for cleaner fuels from 2020.
However, soaring freight rates in the past two weeks prompted Asian buyers to bid up for cargoes that ship over shorter distances such as oil from Russia.
These factors pushed spot premiums for ESPO Blend crude, loading from Russia’s Pacific port of Kozmino, to hit an all-time high of nearly $9 a barrel to Dubai quotes in a Surgutneftegaz [SNGS.MM] spot tender for two cargoes loading in early December.
The spot premium for Russian Sokol crude also jumped to a five-year-high of around $8.30 a barrel to Dubai quotes as ONGC Videsh [ONVI.NS] sold a cargo at that level to a Japanese refiner earlier this month, traders said.
Freight rates soared to new highs over the past couple of weeks after nearly 300 oil tankers, or 3% of the global fleet, were placed off limits as companies fear violating U.S. sanctions against Iran and Venezuela.
“Russia’s Urals (crude) has been doing fine this year mostly thanks to sanctions against Iran and Venezuela and now ESPO has clearly benefited. U.S. sanctions really do Russian oil grades good,” a Western trader said.
Although spot premiums for crude have risen across the board, Russian crude grades are being favoured by Asian buyers “mainly due to freight”, said a Chinese trader.
“Short-haul cargoes will be attractive,” he added.
It takes four days to ship a cargo of ESPO crude from Russian’s Kozmino port to China’s Shandong port and three days to Japan’s Chiba port, according to data on Refinitiv Eikon.
(GRAPHIC - Russian crude premiums to Asia soar after freight rates jump: here)
The Russian cargoes are expected to head to Japan where refiners will ramp up output during fourth quarter to meet peak winter demand, traders said.
They added that uncertainty over Saudi light crude supplies after the attack is also supporting light crude prices.
Oil production at the world’s top exporter has rebounded back to 11.3 million bpd and was on track to reach 12 million bpd by the end of November, but some traders said it could take longer to repair the crude oil processing plants.
“Although the overall output is back it does not mean the supply of Arab Light and Arab Extra Light is back to normal,” said an Asian refinery source.
“Some smaller refineries need to buy spot cargoes in advance to hedge the risks.”
U.S. crude exports to Asia, which have slumped due to record freight costs, stirred on Thursday as rates slid and the premium in Asia for Russia’s ESPO Blend oil sent buyers back to U.S. grades, according to market sources.
Oil shipping costs for United States Gulf Coast to Asia cooled this week from record highs on the prospect of more vessels becoming available. Nearly 300 oil tankers globally were placed off limits due to U.S. sanctions on Iran and Venezuela.
Seventeen supertankers returned to service in October after being sidelined for overhauls, as 11 entered drydocks. That was the first overall increase in available ships since May, according to shipbroker McQuilling Services.
Exxon Mobil Corp provisionally chartered the Very Large Crude Carrier (VLCC) KHK Empress to transport crude from the U.S. Gulf Coast to Singapore for $11.5 million, or $5.75 a barrel, according to four market sources. Exxon declined to comment.
Trafigura AG also tentatively booked the Ascona to ship U.S. crude to South Korea for $12.9 million, or $6.45 a barrel, three market sources said. Trafigura had no immediate comment on the charter.
Both were below rates of between $16 million and $17.5 million, or $8 to $8.50 per barrel, quoted earlier in the week for U.S. to Asia routes, shipbrokers said. Assessed rates peaked on Friday around $11 a barrel.
Arbitration opportunities to ship U.S. crude to Asia also have emerged with Russia’s ESPO Blend crude climbing to record premiums in the last month, dragging other grades sold in Asia higher, traders said.
The price of WTI delivered into Singapore was assessed on Thursday at more than $5 a barrel over dated Brent, covering freight costs and providing some margin, traders said.
“Asia needs oil. It’s the shortest region globally. They will pull (the arbitration window) open,” a U.S. trader said.
In addition to U.S. sanctions on Chinese tankers that crimped supply, some vessels have been drydocked awaiting exhaust scrubbers to meet regulations that take effect on Jan. 1. Those regulations ban ocean-going vessels from using fuel with sulfur content above 0.5% unless they are equipped with the scrubbers.
The return of some tankers into service could signal a further drop in global oil freight rates. Another factor affecting demand was refiners including China’s Sinopec cut runs and a series of failed charters adding to available tonnage, said Oliver Ge, a senior advisor at McQuilling Services.
U.S. crude oil refinery inputs averaged 15.4 million barrels per day during the week ending October 11, 2019, which was 221,000 barrels per day less than the previous week’s average. Refineries operated at 83.1% of their operable capacity last week. Gasoline production decreased last week, averaging 10.0 million barrels per day. Distillate fuel production decreased last week, averaging 4.7 million barrels per day.
U.S. crude oil imports averaged 6.3 million barrels per day last week, up by 70,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 6.3 million barrels per day, 18.2% less than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 651,000 barrels per day, and distillate fuel imports averaged 197,000 barrels per day.
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 9.3 million barrels from the previous week. At 434.9 million barrels, U.S. crude oil inventories are about 2% above the five year average for this time of year. Total motor gasoline inventories decreased by 2.6 million barrels last week and are about 2% above the five year average for this time of year. Finished gasoline and blending components inventories both decreased last week. Distillate fuel inventories decreased by 3.8 million barrels last week and are about 11% below the five year average for this time of year. Propane/propylene inventories decreased by 0.3 million barrels last week and are about 12% above the five year average for this time of year. Total commercial petroleum inventories decreased last week by 1.6 million barrels last week.
Total products supplied over the last four-week period averaged 21.1 million barrels per day, up by 5.4% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.3 million barrels per day, up by 2.6% from the same period last year. Distillate fuel product supplied averaged 4.1 million barrels per day over the past four weeks, down by 2.0% from the same period last year. Jet fuel product supplied was down 1.9% compared with the same four-week period last year.
Domestic production unchanged at 12,600,000 bbls day
Exports 3,248,000 bbls day down 153,000 bbls day
Cushing 43,000,000 bbls up 1,300,000 bbls
Saudi Aramco has postponed the launch of what is expected to be the world’s largest initial public offering, according to people familiar with the matter.
The state-owned oil giant, which had been preparing for an Oct. 20 official launch of the share sale, is pushing back the IPO until December or January, two people familiar with the matter said.
“It is a last-minute decision,” said one senior Saudi official. “A few things needed to be fine tuned including financial figures for the third quarter,” he said.
Last month, Saudi officials discussed delaying Aramco’s IPO, following attacks on the company’s largest oil facilities, which severely curtailed the kingdom’s output. They later decided to press on with the plan, according to people familiar with the matter.
https://www.marketwatch.com/story/saudi-aramco-will-delay-ipo-until-at-least-december-2019-10-17
The Kenney government’s so-called “energy war room,” which is aimed at countering criticism of Alberta’s energy industry, is coming under fire again after the province revealed its “internal operations” won’t be subject to freedom of information laws.
“Albertans should be very worried about this, because what this is essentially doing is saying they (citizens) have no right to know what their government is doing in one of its most secretive areas, in one of its most controversial areas,” said Sean Holman, an associate professor of journalism at Calgary’s Mount Royal University.
Holman added that the secrecy will make it difficult to hold the government to account for its actions in the war room sphere.
“[Freedom of information laws] are the only laws we have that allow people to get access to information that the government would not otherwise voluntarily disclose,” he said.
“So this is very disturbing and outside democratic norms.” Tweet This
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On Wednesday, Energy Minister Sonya Savage announced the war room was now a legal entity and incorporated and would be called the Canadian Energy Centre. She said the program was expected to be up and running before Christmas.
“There will be social media. There will be traditional media,” Savage said.
“There will be speaking engagements, anything that you can get that can be utilized to get the story out because over the last decade that story has been framed, and the narrative has been set, by opposition to our oil and gas sector.” Tweet This
READ MORE: Alberta government says its energy war room will launch soon under ‘Canadian Energy Centre’ name
The war room will be managed by former UCP candidate Tom Olsen and have a budget of $30 million. The government has confirmed Olsen’s annual salary will be $194,252.
On Thursday afternoon, a spokesperson for Premier Kenney’s office issued a statement explaining why some details of how the war room operates will be kept secret.
“When discussing details of the newly incorporated Canadian Energy Centre, the minister of energy was not sufficiently clear regarding FOIP legislation’s applicability to the CEC,” Christine Myatt said. “Information that’s under control of the Government of Alberta, including information provided to government by the CEC and vice versa, is subject to FOIP.
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“The CEC’s internal operations are not subject to FOIP, as this would provide a tactical and/or strategic advantage to the very foreign-funded special interests the CEC is looking to counter. For example, we would not let those foreign-funded special interests seeking to attack our province see our detailed defence plans.
“It should be noted that CEC is still subject to PIPA, the Whistleblowers’ Act and to audit by the Auditor General.”
Myatt explained that the CEC is a provincial corporation under the Financial Administration Act and that the ministers of justice, energy, and environment are the board members, while the Crown, “on behalf of the people of Alberta, is the shareholder.”
Holman said beyond the fact the war room will not be subject to freedom of information requests, he has concerns about the overall threat the program poses to democracy in Alberta.
“We’re talking about an operation that is essentially surveilling civil society groups and looking to intimidate them for doing things that are part of democratic society,” he said. “People should have a right to dissent, whether it’s involving the government or big business, and what this energy war room is designed to do is to suppress that kind of dissent.
“I think it’s really disturbing. A democratic government is not a secretive government and what this war room is, is extremely secretive.” Tweet This
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Plans to create an energy war room were first announced by Jason Kenney as he was running to become premier. He said he believed anti-oil activists and others were spreading misinformation about Alberta’s energy sector.
He also suggested he believes environmental groups receive considerable funding from foreign actors, and that there may be a conspiracy by those foreign actors to keep Alberta’s oil and gas landlocked by preventing pipelines from getting built.
The Alberta government has commissioned a $2.5-million public inquiry into how anti-oil groups are funded.
Foreign actors and corporations have a significant stake in Alberta’s energy industry even though foreign interest is declining, research shows.
READ MORE: Foreign share of production in Alberta’s oilsands falls from 33% to 16%, analysis shows
According to a Canadian Press analysis of Alberta Energy Regulator production numbers, in 2018, about 573,000 barrels per day of oilsands output was attributable to non-Canadian companies.
According to The Canadian Press, the 12 foreign companies that currently have commercial oilsands production in Alberta are composed of three from the U.S. (ConocoPhillips, Exxon Mobil, Chevron), three from China (CNOOC or China National Offshore Oil Corp., PetroChina, Sinopec), and one each from Britain (BP), the Netherlands (Shell), France (Total S.A.), Hong Kong (Sunshine Oilsands), Japan (JACOS) and South Korea (Harvest Operations).
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–With files from Global News’ Tom Vernon and The Canadian Press
But the state-owned company denied reports the attack had originated from Saudi soil.
Iran vowed on Saturday not to let an attack on one of its oil tankers off the coast of Saudi Arabia to go unanswered, the semi-official ISNA news agency reported.
Ali Shamkhani, secretary of the Supreme National Security Council, said clues had been uncovered as to who was behind what he called a "missile attack" on the Sabiti tanker.
"Maritime piracy and wickedness in international waterways... will not be left unanswered," he said, quoted by ISNA.
"By reviewing the available video and gathered intelligence evidence, the primary clues to the dangerous adventure of attacking the Iranian oil tanker in the Red Sea have been uncovered," he added.
Shamkhani warned of "disturbing risks" for the global economy as a result of insecurity in international waterways.
The National Iranian Tanker Company, which owns the Sabiti, said its hull was hit by two separate explosions on Friday off the Saudi port of Jeddah,
But the state-owned company denied reports the attack had originated from Saudi soil.
The attack caused oil to spill from the tanker into the Red Sea, the NITC said, before it was eventually controlled and the vessel began slowly moving back towards Gulf waters.
According to the latest data from shipping monitors Marine Traffic, the Sabiti was still in the Red Sea about 400 kilometres south of Jeddah.
The incident comes after a spate of still unexplained attacks on shipping in and around the vital seaway to the Gulf involving Iran and Western powers, as well as drone attacks on Saudi oil installations.
Washington accused Tehran of attacking the vessels with mines and to be behind the drone assault, something it strongly denied.
In a statement, Iran's government spokesman Ali Rabiei called Friday's attack "cowardly" and said Tehran would give a "proportionate response" following investigations.
"The question now is, those who accused Iran of disrupting free maritime transport in the Persian Gulf and the attack on Aramco installations with no proof, are they ready to once again defend the principles of free maritime transportation in international waters and condemn such an attack on an Iranian ship?" he said.
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NICOSIA, Cyprus — The president of the European Council urged Turkey Friday to stop “illegal” drilling off Cyprus, saying those activities harm efforts to reunify the ethnically split island nation and undermine Ankara’s relations with the EU.
Donald Tusk said his presence in the war-divided Cypriot capital is a demonstration of the European Union’s “full solidarity” with member-state Cyprus.
Last week, Turkey stepped up its actions by dispatching a warship-escorted drill ship to waters where the Cypriot government licensed Italian energy company Eni and partner Total of France to conduct an oil and gas search.
Tusk said EU leaders have already "strongly condemned" Turkey's previous drilling in an area where Cyprus has exclusive economic rights and that the EU "stands united" with the country in light of Turkey's latest actions.
But Cypriot President Nicos Anastasiades pressed for “a more concrete response,” saying that the EU has the tools to safeguard its credibility and that “legality ought to prevail over the rule of the jungle” Turkey wants to impose in the eastern Mediterranean.
Oil boss: Stop drilling if Turkish warships arrive Eni CEO Claudio Descalzi said he doesn't want "to have a war break out to drill wells."
Turkey doesn’t recognize Cyprus as a state and says it’s acting to protect its interests and those of breakaway Turkish Cypriots with regard to the area’s energy reserves.
The European Union had previously imposed an initial batch of sanctions against Turkey over its drilling activities off Cyprus.
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Greek Foreign Minister Nikos Dendias has said top diplomats from EU member states will decide next week how to respond to the drilling.
Cyprus has been divided since a Turkish invasion in 1974, which followed an abortive coup by supporters of union with Greece.
BP will take charges of $2 to $3 billion in the third quarter, the British energy firm said on Friday, as it looks to reach divestments worth $10 billion by the end of 2019, a year ahead of schedule.
In a statement, London-based BP said it expects to agree asset sales of $10 billion by end-year after its $5.6 billion sale of its Alaskan business to Hilcorp [HILCO.UL] and divestments in U.S. shale gas.
BP shares were down 1.1% by 0948 GMT compared with a 1.3% gain in the broader European energy index.
The non-cash, non-operating, after-tax charge will impact the company’s headline profit figure but not its underlying cashflow, a spokesman said.
BP announced the disposal program following its $10.25 billion acquisition of BHP’s shale business last year, its largest purchase in three decades.
The planned third-quarter impairment charges are expected to increase BP’s gearing - the ratio between debt and market capitalization - to the top end of the 20% to 30% target, BP said.
Debt levels and gearing are expected to move to the middle of the range through 2020.
BP’s third-quarter oil and gas production will be impacted by maintenance in some high-margin regions, BP said.
Output in the U.S. Gulf of Mexico was “significantly disrupted” by Hurricane Barry, with facilities shut down for around 14 days.
BP is scheduled to report its results on October 29.
India, one of the world’s largest consumers of oil and coal, is investing $60 billion to build a national gas grid and import terminals by 2024 in a bid to cut its carbon emissions, the oil minister said on Sunday.
India has struggled to boost its use of gas, which produces less greenhouse gas emissions than coal and oil, because many industries and towns are not linked to the gas pipeline network.
Gas consumption growth was running at 11% in 2010 but growth slid to just 2.5% in the financial year 2018/19.
Oil Minister Dharmendra Pradhan told reporters at India Energy Forum by Ceraweek that companies were investing $60 billion in the network and building new gas import facilities to link all states by mid-2024, when the government’s term ends.
“I am not talking about potential investment. This number relates to the project that are under execution,” he said.
Prime Minister Narendra Modi has previously set a target to more than double the share of gas in India’s energy mix to 15% by 2030.
India’s biggest gas utility Gail Ltd (GAIL.NS) has said it was close to completing the 2,660 km (1,660 miles) Urja Ganga pipeline project, connecting the eastern states of Bihar, West Bengal, Jharkhand and Odisha. The pipeline will have capacity for 16 million standard cubic meters per day (mscmd) of gas.
“The Urja Ganga project ... will be ready by the end of 2020,” Pradhan said on the conference sidelines.
India’s overall gas consumption is about 166 mscmd.
The minister said the government had started building the northeast gas grid to connect eight states in northeastern India, a region bordering Bhutan, Myanmar, Bangladesh and China. He said the grid would be ready by 2023.
He added that, before the end of government’s current term, “India will be connected by a pipeline ring that will help transport gas from any corner of India to a demand center.”
Most of India’s liquefied natural gas (LNG) import terminals are in the west, making it difficult for the industry in the east and elsewhere to secure regular gas supplies.
French energy giant Total SA (TOTF.PA) will buy a 37.4% stake in Indian gas distribution company Adani Gas (ADAG.NS), as it looks to capitalise on the South Asian country’s push for cleaner sources of energy.
A logo of French oil company Total is seen at an office building in La Defense business district in Courbevoie near Paris, France, October 12, 2019. REUTERS/Regis Duvignau/Files
Total is the third foreign oil major to enter India’s gas sector after BP Plc (BP.L) and Shell (RDSa.L), and it comes at a time when India is spending heavily to cut its carbon emissions.
Indian Prime Minister Narendra Modi has set a target to more than double the share of gas in the country’s energy basket to 15% by 2030, while Total has embarked on a series of deals this year to expand its liquefied natural gas (LNG) portfolio.
Total will buy up to 25.2% in Adani Gas from public shareholders at 149.63 rupees per share, representing an 8.7% premium to the stock’s last close and valuing the stake at 41.47 billion rupees ($585 million).
It will also buy another 12.2% stake from the Adani family at an undisclosed price, according to stock exchange filings.
After the deal, the Adani family and Total will each hold 37.4% stake in Adani Gas, while public shareholders will own the remaining 25.2%.
Shares of Adani Gas soared 18.4% on Monday after the deal was announced, while the broader NSE index .NSE rose 0.3% in early trade.
“The natural gas market in India will have strong growth and is an attractive outlet for the world’s second-largest LNG player that Total has become,” Total Chairman and CEO Patrick Pouyanné said in a statement.
“Adani will bring its knowledge of the local market and its expertise in the infrastructure and energy sectors. This partnership with Adani is cornerstone to our development strategy in this country,” added Pouyanné.
Total and Adani plan to establish a joint venture to market LNG in India and Bangladesh.
Speaking later at a conference in New Delhi, Pouyanné said the deal will take 6 months to complete, adding that the energy major was looking to capture a substantial part of the Indian gas market with Adani.
Total was also in discussions with partners including Adani for partnership in renewable energy, he said at the India Energy Forum by CERAWeek.
Last month, Total completed the acquisition of Anadarko’s (APC.N) 26.5% stake in the Mozambique LNG project for $3.9 billion, while in June it took over Toshiba’s (6502.T) U.S. LNG business.
ConocoPhillips (COP.N) has agreed to sell its northern Australian business to partner Santos Ltd (STO.AX) for $1.39 billion, in a deal that will hike the Australian group’s output by 25% and boost its position in the global gas market.
The deal, which was not unexpected, marks the second major acquisition by Santos in less than a year, following a sharp turnaround in its fortunes under Managing Director Kevin Gallagher, and pushed its shares up 7% in early trade on Monday.
ConocoPhillips, which has been focusing on its U.S. shale assets, will quit the Darwin LNG plant, which it opened in 2006, and gas fields off northern Australia, but hold on to its stake in the Australia Pacific LNG plant in Queensland state.
“While we believe the Darwin LNG backfill project remains among the lower cost of supply options for new global LNG supply, this transaction allows us to allocate capital to other projects,” ConocoPhillips Chief Operating Officer Matt Fox said in a statement.
The move comes as the Bayu-Undan gas field that feeds Darwin LNG is set to run dry in 2022 and the project’s owners near a decision on which field to develop next to keep the plant open, with Santos aiming to develop the Barossa field.
“The big prize here is pushing forward with development (of Barossa) and setting up the framework to develop other resources in the region over time,” Gallagher told reporters on a conference call.
The deal, set to close in the first quarter of 2020, is expected to boost Santos’ earnings per share by 16% and increase its production by 25% in 2020, the company said. It adds to its stakes in the Gladstone LNG project and PNG LNG in Papua New Guinea.
Santos has agreed to pay a further $75 million if a final investment decision is reached on developing the Barossa field. It plans to fund the whole acquisition out of cash and new debt.
DARWIN STAKE SALE
The deal gives Santos control over the future of Darwin LNG, the second-oldest of Australia’s 10 LNG plants, at a time when it is vying against several LNG projects worldwide to line up gas buyers to extend its life.
“It seems like a good deal. They go from being a small joint venture partner to being the operator,” said Stephen Butel, an analyst at Platypus Asset Management. “It allows them to take control of the situation there.”
Santos will acquire ConocoPhillips’ majority stakes in Darwin LNG and Bayu-Undan, as well as a 37.5% stake in Barossa, but will aim to cut its stakes in Darwin LNG and Barossa to about 40%-50%.
It said it has already reached a preliminary agreement to sell down a 25% stake in Darwin LNG to its Barossa partner SK E&S of South Korea.
It was also in talks with other Darwin LNG partners, which include Japan’s Inpex Corp (1605.T), Italy’s Eni SpA (ENI.MI), Japan’s JERA (9501.T) (9502.T) and Tokyo Gas (9531.T), to sell equity in Barossa and Darwin LNG.
At the same time, Santos said it is aiming to line up contracts for 60%-80% of LNG volumes for more than 10 years before taking a final investment decision on Barossa — the first time it has spelled out a target for contracts.
“It’s very competitive. It’s positioned well. We’re very confident we’ll get it away. And it’s got very robust economics even in this soft market that we find ourselves in today,” Gallagher said.
zoom Image courtesy of NNPC
The Nigerian National Petroleum Corporation (NNPC) signed a $2.5bn pre-payment agreement with Nigeria LNG for upstream gas development projects to supply gas to NLNG Trains 1 – 6.
NNPC’s general managing director, Mallam Mele Kyari said the agreement will help resolve the issues regarding gas supply to trains 1-6, at the facility, adding that there was a need to fast-track action on the process of bringing more trains on stream.
He added that the pre-payment gas supply agreement was a milestone which aligned with the government’s aspirations of monetizing the nation’s gas resources, protecting the investment in NLNG, ensuring full capacity utilization (22mtpa LNG and 5mtpa NGLs) of Trains 1-6 plants and providing new vistas of growth opportunities in the nation’s LNG sector.
Additionally, NNPC challenged shareholders of Nigeria LNG to work towards expanding the production capacity of the project beyond Train 7 at the liquefaction plant on Bonny Island.
The Train 7 project is expected to expand NLNG’s production capacity by 35 percent from 22 million tonnes per annum (mtpa) to 30 mtpa.
NLNG is owned by four shareholders, namely, the Federal Government of Nigeria, represented by NNPC (49 percent), Shell (25.6 percent), Total (15 percent), and Eni (10.4 percent).
In September, Nigeria LNG signed a Letter of Intent (LOI) for the engineering, procurement, and construction (EPC) of Train 7 with a consortium comprising Saipem, Chiyoda and Daewoo.
London — Saudi Arabia is focused on a domestic stock market listing for its state oil company, Aramco, and no decisions have been made for any international share sale, the Saudi ambassador to the UK told S&P Global Platts on Monday.
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"We are tending now towards looking at a Tadawul listing," said Prince Khalid bin Bandar, referring to the Saudi stock exchange, after speaking at the Royal United Services Institute in London. "But if that doesn't work, then we will look otherwise. But the important thing is to be pragmatic, depending on the situation, and we'll wait and see how [the domestic listing] goes."
No international venues had been ruled out if a listing outside Saudi Arabia proceeds, he added.
"Everything is a candidate," the prince said. "We will do what's right for Saudi Arabia."
The much hyped Aramco IPO, first announced by Crown Prince Mohammed bin Salman in 2016, is a centerpiece of the kingdom's economic transformation plan, with officials aiming for a company valuation of $2 trillion, though analysts say $1.5 trillion is more realistic.
If the kingdom's desired valuation is achieved, the rumored 5% public listing could bring in $100 billion that could be used for development programs aimed at weaning Saudi Arabia off its reliance on oil revenues.
Reports indicate that the kingdom could float a small portion of the planned total listing -- perhaps 1% or 2% -- on the Tadawul, before looking internationally, where exchanges in London, New York, Tokyo and Hong Kong are among the contenders.
The Tadawul is the Middle East's largest exchange, with a market cap of Riyal 1.80 trillion ($479 billion). A 1% listing, even at the lower range of valuation estimates, would make Aramco one of the largest stocks traded on the Saudi bourse in terms of market value.
Details of the IPO will be announced later this month, Aramco Chairman Yasir al-Rumayyan said Monday, according to a report by Russia's Prime news agency.
"The Saudi Aramco IPO will happen very soon, our plans are moving along quickly and smoothly. You will hear about it very soon. I think we can expect this month," Rumayyan said during the Russia-Saudi Investment Forum held in Riyadh on the sidelines of Russian President Vladimir Putin's state visit to Saudi Arabia.
VAST RESERVES
Saudi Aramco is the world's most profitable company and biggest oil producer, with exclusive rights to pump all of the country's vast reserves.
It claims a maximum sustained crude production capacity of about 12 million b/d, though significant chunks remain offline due to repairs following last month's attacks on its critical Abqaiq crude processing facility and Khurais oil field. Full capacity should be restored by the end of November, officials have said.
Saudi Arabia plans to produce 9.86 million b/d of crude in October and November, energy minister Prince Abdulaziz bin Salman said Monday, according to Prime news agency, with exports currently around 6.9 million to 7 million b/d.
The kingdom has a production quota of 10.31 million b/d under the OPEC/non-OPEC production cut accord, though it has held its output significantly below that cap as it seeks to accelerate the rebalancing of the oil market, given that oil prices remain far below the $80-$85/b that many analysts say Saudi Arabia needs to balance its budget.
Aramco also has significant downstream and storage assets globally, including refineries in the US, China, Japan and South Korea, in addition to domestic refineries.
As an alternative to an IPO, analysts have suggested that a private placement could be brokered with sovereign wealth funds.
Earlier Monday, Kirill Dmitriev, CEO of Russia's sovereign wealth fund the Russian Direct Investment Fund, said Russian investors were interested in the listing, Prime reported.
-- Herman Wang, herman.wang@spglobal.com
-- Rosemary Griffin, rosemary.griffin@spglobal.com
-- Edited by James Burgess, newsdesk@spglobal.com
London — EU foreign ministers agreed Monday that sanctions should be imposed against parties involved in Turkey's campaign of exploration drilling in the gas-rich waters offshore Cyprus.
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The latest escalation in tensions between Brussels and Ankara follows the move earlier this month by Turkey's state-owned Turkish Petroleum to position one of its drill ships in a Cypriot-licensed block.
The EU in July already imposed limited sanctions against Turkey, but the EU Council said Monday it wanted to target measures against those "responsible for or involved in the illegal drilling activity of hydrocarbons in the Eastern Mediterranean."
"The Council agrees that a framework regime of restrictive measures [...] is put in place, and invites the High Representative [Federica Mogherini] and the [European] Commission to swiftly present proposals to this effect," it said.
On Friday, European Council President Donald Tusk said the EU stood in "full solidarity" with Cyprus over the growingcrisis in the East Mediterranean.
Cyprus is already home to as much as 550 Bcm of gas resources following the Aphrodite, Calypso and Glaucus discoveries of recent years, so the stakes are high as the dispute over maritime rights continues to intensify.
Turkey has previously warned it would increase its presence in the East Mediterranean if EU sanctions were imposed.
BLOCK 7 RIGHTS
Turkish Petroleum in early October sent its drillship, the Yavuz, to an unspecified site in Cyprus' Block 7, which Nicosia says is part of its maritime Exclusive Economic Zone (EEZ).
S&P Global Platts trade flow software cFlow shows the Yavuz as being in the northwestern part of Block 7.
In September, the Cypriot government signed agreements with France's Total and Italy's Eni giving them the license todrill in Block 7.
Eni CEO Claudio Descalzi said Friday the company remained committed to the exploration of the Cypriot EEZ and its "contractual commitments" with Cyprus and that it was planning a joint exploration campaign in the first half of 2020 together with Total.
Turkey, though, has warned non-Turkish companies not to drill in the block, saying it has the right to drill in the northwest of Block 7 under its interpretation of maritime law.
It is the first time Turkey has moved into a block already licensed by Cyprus.
The Yavuz entered the Mediterranean in July and in August began drilling the Karpaz-1 in the Bay of Gazimagusa off the east coast of Cyprus, before returning to port on the south coast of Turkey in early September.
Turkey's first drillship, the Fatih, is continuing to drill off the northwest coast of Cyprus, where it has been located since May.
Neither area has been licensed by Cyprus to date.
-- Stuart Elliott, Stuart.Elliott@spglobal.com
-- Edited by Jonathan Dart, jonathan.dart@spglobal.com
Singapore — Crude oil futures were lower during mid-morning trade in Asia Monday as the market remained cautious following the partial trade deal between the US and China.
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At 11:12 am in Singapore (0312 GMT), ICE Brent December futures were down 25 cents/b (0.41%) from Friday's settle at $60.26/b, while the NYMEX November light sweet crude futures contract was 27 cents/b (0.49%) lower at $54.43/b.
The US and China have reached a partial agreement Friday that covers agricultural purchases, financial services, currencies and intellectual properties. The agreement came after President Donald Trump met with Chinese Vice Premier Liu He in the White House.
"I agreed not to increase tariffs from 25% to 30% on October 15. They will remain at 25%," US President Donald Trump tweeted on Sunday.
"The relationship with China is very good. We will finish out the large Phase One part of the deal, then head directly into Phase Two. The Phase One deal can be finalized and signed soon!" Trump added.
While the partial agreement between the two countries had initially boosted sentiments, analysts noted that details were lacking in the deal, while uncertainties remained on other issues not covered in the deal.
"While the market welcomed the deal, it remained cautious over the long term issues underlying the dispute," ANZ analysts wrote in their report on Monday.
"Five uncertainties remain including the delay of December tariff hike, Huawei, the new US entity list, currency manipulation designation and removal of existing tariff," OCBC analysts Tommy Xie and Carie Li wrote in their report on Monday.
Elsewhere, Saudi Arabia was not involved in the attack on the Iranian oil tanker on Friday, its Minister of State for Foreign Affairs Adel Al-Jubeir said Sunday.
Oil prices had jumped Friday following news of the attack on National Iranian Tanker Company's suezmax tanker Sabiti, which had caused an oil spill in the Red Sea. The company has since said the situation was under control and the oil leakage has stopped.
As of 0312 GMT, the US Dollar Index was up 0.13% at 98.155.
--Ada Taib, ada.taib@spglobal.com
--Edited by Norazlina Juma'at, norazlina.jumaat@spglobal.com
Greenpeace activists from the Netherlands, Germany, and Denmark boarded two oil platforms in Shell’s Brent field on Monday in what they say is a protest against plans by the company to leave parts of old oil structures with 11,000 tonnes of oil in the North Sea.
Greenpeace said in a statement on Monday that its climbers, supported by the Greenpeace ship Rainbow Warrior, had scaled Brent Alpha and Bravo and hung banners saying, ‘Shell, clean up your mess!’ and ‘Stop Ocean Pollution’.
Greenpeace claimed that Shell plans to leave parts of four Brent oil platforms at sea with a total of around 640,000 cubic metres of oily water and 40,000 cubic metres of oily sediment, containing more than 11,000 tonnes of oil.
According to Greenpeace, a ban on dumping installations and platforms in the North East Atlantic Ocean was agreed in 1998 by all members of the OSPAR Commission and Shell has requested an exemption from the UK government.
“Shell’s plans are a scandal and go against international agreements to protect the environment. With escalating climate emergency, biodiversity loss and species extinction, we need healthy oceans more than ever. Abandoning thousands of tonnes of oil in ageing concrete will sooner or later pollute the sea. Shell must be stopped,” said Dr Christian Bussau, Greenpeace campaigner on board the Rainbow Warrior.
“We urge OSPAR governments to protect the ocean and not cave in to corporate pressure.”
Germany & Netherlands object
Greenpeace stated: “The UK government is willing to approve Shell’s plans when OSPAR meets in London on October 18. Germany has filed an official objection. The Netherlands will also object and the European Commission has raised serious concerns.”
Namely, Dutch infrastructure minister, Cora van Nieuwenhuizen, earlier in October sent a letter to the Parliament about the country’s position on cleaning up Shell’s oil platforms in the North Sea, saying it was consistent with that of Germany, which has already objected.
She said that, as a party to the OSPAR treaty, the Netherlands would object to the UK’s intention to grant Shell a license to abandon Brent platforms foundations with contaminated material in them.
‘Dangerous precedent’
“The UK government cannot claim to be a global oceans champion while allowing Shell to dump thousands of tonnes of oil in the North Sea,” said Dr Doug Parr, Greenpeace UK’s chief scientist.
“If ministers allow Shell to bend the rules, this will set a dangerous precedent for the decommissioning of hundreds of ageing North Sea platforms in the coming years. Shell made billions from drilling for oil in this region – they shouldn’t be allowed to scrimp and save on the clean-up at the expense of our marine environment.”
“Oil in the base of Shell’s platforms will reach the sea as the concrete structures rot and collapse. Shell’s plans leave a ticking time bomb and that is totally irresponsible,” added Bussau.
In 1995, public support for the Brent Spar campaign pushed Shell to agree to dismantle the oil tank and loading platform on land instead of dumping it in the sea. The campaign also led to OSPAR’s decision in 1998 to ban such dumping in the North East Atlantic.
“Shell is directly fuelling the climate emergency that is causing more extreme storms, floods, droughts and wildfires and bringing misery to millions of people around the world. The company’s reckless business threatens some of the world’s most important ecosystems with extinction and has to be stopped. For us to have a future, toxic oil companies like Shell must have no future,” said Bussau, who was also part of the 1995 Brent Spar protest.
Brent decommissioning
The Shell-operated Brent field, located 115 miles north-east of the Shetland Islands, has produced around three billion barrels of oil equivalent since production started in 1976, which is almost 10% of UK production. The field comprised four large platforms: Alpha (a steel jacket), Bravo, Charlie, and Delta (concrete gravity-based structures).
Shell submitted its decommissioning program for the Brent oil and gas field to the authorities in February 2017. The Brent decommissioning program recommended the upper steel jacket on the Brent Alpha platform to be removed, along with the topsides of the four Brent platforms, debris lying on the seabed, and the attic oil contained within the concrete storage cells of the gravity base structures.
Shell has already removed the Brent Delta and Brent Bravo platform topsides in April 2017 and June 2019, respectively. Both were removed using the Allseas-owned Pioneering Spirit vessel.
Offshore Energy Today Staff
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SINGAPORE (ICIS)--Asia’s naphtha margins have climbed to their highest this year driven by concerns over supply combined with a steady bout of buying, boosting spot premiums.
A container ship at a Tokyo port in Japan. (Photo by Franck Robichon/EPA-EFE/Shutterstock)
Naphtha’s crack spread, a measure of the product’s refining margin, closed on 11 October at $105.83/tonne, the first time this year it has surpassed the $100/tonne mark - a level not seen since October 2018.
The crack spread had languished in negative territory four months ago in mid-June.
In part buoyed by gains in global crude oil futures, open-specification naphtha prices for second-half November delivery averaged at $559.50/tonne CFR (cost and freight) in the morning session on Monday, steady from the previous close on 11 October and at the highest since 22 May, according to ICIS data.
On a free-on-board (FOB) Middle East basis, spot naphtha prices have hit a five-month high of $510.11/tonne as of 11 October, ICIS data showed.
International benchmark December ICE Brent crude oil futures rose by more than 3% last week to settle at $60.51/bbl on 11 October.
Market sentiment was boosted by gains in oil prices, following news reports of an Iranian oil tanker being struck by missiles in the Red Sea near Saudi Arabia, stoking concerns on supply disruptions.
Ever since the attacks at oil facilities in Saudi Arabia on 14 September, along with moves to plug supply shortfalls, naphtha markets have rebounded.
Re-inforcing strong market fundamentals, naphtha's forward market structure has widened significantly in backwardation, with prompt-month values well above forward months.
Second-half November open-specification naphtha prices stood at $24.00/tonne higher than second-half December prices, compared with the backwardated spread of $2.00/tonne a month ago.
Spot naphtha cargoes were transacted at strong premiums, including exports from India, mirroring the firm sentiment amid perceived contraction in supply.
An estimated 2.1m tonnes of naphtha are expected to arrive in Asia this month, lower than September volumes at around 2.5m tonnes, according to industry sources.
India’s Bharat Petroleum Corp Ltd (BPCL) sold a 30,000-tonnes cargo for 3-5 October loading from Mumbai, at a premium near $21/tonne to its pricing formula - sharply higher than the single-digit premium it fetched for a September cargo.
South Korea's Yeochun NCC (YNCC) was understood to have picked up second-half November naphtha at a premium of above $20/tonne to spot CFR Japan quotes, compared with the $10/tonne premium it paid for first-half November supplies.
Focus article by Melanie Wee
Houston oil company Sanchez Energy appears to be drilling its way out of bankruptcy.
The company temporarily placed its drilling operations on hold after seeking Chapter 11 protection, but over the past week filed 13 drilling permit applications with the Railroad Commission of Texas, the state agency regulating the oil and natural gas industry. The company is seeking permission to drill 10 horizontal wells on a pair of leases in Dimmit County and another three on a lease in neighboring Webb County.
The wells target the Briscoe Ranch field of the Eagle Ford geological layer down at total depths ranging from 8,600 to 9,600 feet.
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Parsley Energy Inc (PE.N) said on Monday it would buy smaller peer Jagged Peak Energy Inc (JAG.N) in an all-stock deal valued at $1.62 billion, adding acreage in the oil-rich Delaware shale basin.
Shares of Parsley Energy, which was itself seen as a buyout target for some time, fell about 8.7% in premarket trading to $15.50. Jagged Peak shares were marginally lower after briefly rising on the announcement.
The offer of 0.447 shares of Parsley Class A common stock values Jagged Peak at $7.59 per share, based on Parsley’s closing price on Friday. The offer represents a premium of 11.3% to Jagged Peak’s last close.
“Jagged Peak’s oily, high-margin asset base slots in nicely to our returns-focused development approach, its acreage footprint and water infrastructure dovetails into our legacy Delaware Basin position,” Parsley’s Chief Executive Officer Matt Gallagher said in a statement.
Including Jagged Peak’s debt of about $625 million as of June 30, the deal is valued at $2.27 billion.
Parsley expects the deal to generate savings of about $25 million in the first year, and $40-$50 million of annual savings thereafter.
The companies expect the deal to close in the first quarter of 2020.
Texas-based Parsley said it expects the “low-premium” deal to immediately add to 2020 cash flow per share.
After the deal, Parsley will have about 267,000 net acres in the Permian basin, consisting of 147,000 net acres in the Midland Basin and 120,000 net acre footprint in the Delaware Basin.
Global energy giant Exxon Mobil Corp (XOM.N) will offer its expertise and technology to India’s biggest state-owned explorer Oil and Natural Gas Corp Ltd (ONGC.NS) to help develop its resources in offshore blocks, according to two sources directly privy to the development.
The memorandum of understanding (MoU), signed late Monday, will be later signed as a definitive deal after Exxon studies the blocks of the company, one of the sources told Reuters.
Lately, India is generating a lot of interest worldwide in its oil and gas operations, as growing demand amid a global slowdown and government policies have made investments and returns attractive.
"Witnessed the exchange of a MoU between ONGC and ExxonMobil to identify areas for exploration in deep water in east and west coast of India," Oil Minister Dharmendra Pradhan said in a tweet here
ONGC and ExxonMobil will also jointly identify areas to submit bids for more exploration assets in India, he added.
ONGC is currently developing deep water oil and gas blocks in India’s east coast, which are expected to come onstream by 2020 and produce 15 million standard cubic meters per day (mscmd) of gas at its peak.
On Monday, Exxon signed another memorandum with India’s biggest refiner Indian Oil Corp Ltd (IOC.NS) to explore ways to supply liquefied natural gas to meet India’s 1burgeoning gas demand.
French energy major Total SA (TOTF.PA) also announced that it would buy around 35% stake in India’s Adani Gas Ltd.
“It is a non-binding agreement. It is a technical tie up. The MoU provides a framework to enable future tie ups between the two companies,” one of the sources said.
Norway’s Aker BP (AKERBP.OL) fell short of its third-quarter oil and gas output target and will take an impairment charge of $80 million, it said on Monday, sending its shares down more than 4%.
Daily output fell to 146,100 barrels of oil equivalents per day (boepd) in the July-September quarter period from 150,600 boepd a year earlier and was short of a target of around 158,700 boepd announced in April.
Aker BP blamed the fall on a delay in starting new wells at the North Sea Valhall field following maintenance in June, adding there was no impact on reserves.
The Oslo-listed firm, 30% owned by BP Plc (BP.L) and 40% by Norway’s Aker ASA (AKER.OL), also said it would book an goodwill impairment charge of $80 million and would see an additional $14 million in costs stemming from repair work at one of its North Sea fields.
As the goodwill cost incurred is not deductible under Norway’s tax code, Aker BP’s tax bill for the third quarter will be “well above” 100% of its profits, the company said.
However, the start-up of the new wells at Valhall, and the ramp-up of the giant Johan Sverdrup oilfield which started production in October will significantly boost output going forward, it said.
Aker BP has a 11.6% stake in the Sverdrup field, which is expected to ramp up production to 440,000 boepd by summer 2020, its operator Equinox (EQNR.OL) has said.
That translates into more than 50,000 boepd for Aker BP, meaning that its total production could top 200,000 boepd.
“With Sverdrup first oil on Oct. 5, Aker BP’s 2019 production guidance of 155,000-160,000 boepd should be safe,” Sparebank 1 Markets analyst Teodor Sveen-Nilsen, who has a “buy” recommendation on the stock, wrote in a note to clients.
Source: U.S. Energy Information Administration,
Note: The propane price is the weighted average of Midwest and Northeast prices. All other fuels reflect national averages. U.S. Energy Information Administration, Winter Fuels Outlook , October 2019The propane price is the weighted average of Midwest and Northeast prices. All other fuels reflect national averages.
Republished at 10:00 a.m. on Wednesday, Oct 9 to correct the percent change in propane expenditures.
On average across the United States, households can expect heating expenditures this winter (October through March) to be lower than last winter’s, according to the U.S. Energy Information Administration’s (EIA) Winter Fuels Outlook, released at noon today. EIA expects households that primarily use electricity or natural gas as their heating source to spend slightly less than last winter, households that use heating oil to spend 4% less, and households that use propane to spend 15% less. Only natural gas bills in the South are likely to rise significantly, by about 4%, primarily as a result of higher regional natural gas prices. EIA’s forecast of winter heating expenditures are based on fuel price and consumption forecasts from EIA and weather forecasts from the National Oceanic and Atmospheric Administration (NOAA).
Because U.S. winter heating demand is highly dependent on weather, EIA’s Winter Fuels Outlook includes two additional forecasts, one for colder and one for warmer weather this winter. EIA uses heating degree days to measure colder or warmer winter weather. Heating degree days are daily temperature differences compared with a base temperature of 65 degrees Fahrenheit (about 18 degrees Celsius). For example, a daily average temperature of 45 degrees is equivalent to 20 heating degree days. When added up across a winter, colder temperatures mean more total heating degree days.
To produce regional values over the winter, NOAA weights heating degree days by population and sums them over time. NOAA expects the United States as a whole to experience 3,635 heating degree days this winter, a value slightly lower (warmer) than the average of the previous 10 winters. Seven of the past 10 winters have been within 10% (either warmer or colder) of NOAA’s forecast.
Source: U.S. Energy Information Administration, based on National Oceanic and Atmospheric Administration
Fuel expenditures in EIA’s Winter Fuels Outlook reflect consumption and the resulting bills for all uses of energy in the household—not just heating. This approach contributes to the differences in expected expenditures across fuels. Natural gas is the most common space heating fuel in 29 states and the District of Columbia. Electricity tends to be more common in southern states.
Source: U.S. Energy Information Administration, based on Census Bureau American Community Survey 2018
Heating oil is much more common in the Northeast than in other regions and is the most prevalent primary heating fuel in four Northeastern states. Propane is more common in the Midwest, but it is not the most prevalent heating fuel in any state.
EIA’s Winter Fuels Outlook also considers adequacy of stored energy at the beginning of the winter season. Natural gas storage has seen a significant rebound in the United States over the past year. Working natural gas inventories in the Lower 48 states began the injection season on April 1 almost 30% lower than the previous five-year average. By the end of October, the end of the injection season, EIA expects working gas inventories in the Lower 48 states to be 2% higher than the previous five-year average.
Although the total of all heating oil inventories in the Northeast was 26% lower than the previous five-year average at the end of September, EIA does not expect significant supply disruptions or price fluctuations. Heating oil can be transported to the Northeast by pipeline, coast-wise compliant vessels from other U.S. ports, and imports. In addition, EIA’s forecast of strong distillate margins is likely to encourage refiners to increase refinery runs and maximize production of distillates, including heating oil.
More information on EIA’s forecasts for winter heating fuels’ prices, consumption, and expenditures will be available in the Winter Fuels Outlook released later today.
Principal contributor: Stacy MacIntyre
Duke Energy Corp.’s DUK subsidiary, Duke Energy Carolinas, recently announced its agreement with Anderson County, S.C., to build energy storage project at the Anderson Civic Center.
Notably, the project will be used as back-up power with a capacity to serve the Civic Center for at least 30 hours based on normal usage during outages. The company has submitted a request to the Public Service Commission of South Carolina for approval of the lease agreement for the land from Anderson County.
After the expected completion of final engineering study later in 2019, the project will go through a competitive bidding process for construction and is expected to be in service in early 2021.
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ABU DHABI, 15th October, 2019 (WAM) -- The Abu Dhabi National Oil Company,ADNOC, signed today a comprehensive strategic framework agreement with the Public Joint Stock Company Gazprom Neft,Gazprom Neft, to explore new opportunities for collaboration in both the upstream and downstream sectors, as well as in artificial intelligence and other innovative technologies.
The cooperation brings together two leading energy producers to collaborate in areas of strategic importance for both companies and reinforces the strong bilateral relations between the United Arab Emirates,UAE, and Russia. It also underscores ADNOC’s drive to leverage value-add partnerships to unlock and maximise value across its full value chain as it accelerates delivery of its 2030 smart growth strategy.
In celebration of the friendly ties between both countries, the exchange of the signed framework agreement was witnessed by His Highness Sheikh Mohamed bin Zayed Al Nahyan, Crown Prince of Abu Dhabi and Deputy Supreme Commander of the UAE Armed Forces, and His Excellency Vladimir Putin, President of the Russian Federation, on the occasion of the president’s state visit to the UAE.
The agreement was exchanged by Dr. Sultan Ahmed Al Jaber, UAE Minister of State and ADNOC Group CEO, and Mr. Vladislav Baryshnikov, Member of the Management Board and Deputy CEO for International Business Development of Gazprom Neft.
Under the terms of the agreement, ADNOC and Gazprom Neft will jointly explore opportunities for collaboration in relation to Abu Dhabi’s exploration and production concessions. This potential for collaboration in relation to Abu Dhabi’s exploration and production concessions builds on the momentum of the successful conclusion of Abu Dhabi’s debut competitive exploration and production bid round.
In addition, the two partners will jointly assess strategic opportunities for collaboration in sour gas exploration and production. ADNOC is a leader in sour gas field development and production with extensive experience gained from its Shah sour gas field in the Emirate of Abu Dhabi, where it plans to increase production from about 1.3 to 1.5 billion standard cubic feet per day,bscfd, of natural gas. Also, ADNOC is developing the Ghasha ultra-sour gas concession, which is expected to produce more than 1.5 bscfd of natural gas by around 2025.
Both companies will also explore potential opportunities for collaboration in enhanced oil recovery,EOR, techniques that could unlock and maximize value from maturing reservoirs. Collaboration on the various EOR applications will support ADNOC’s production growth plans and enhance hydrocarbon recovery rate towards its 70 percent aspiration, where commercially viable.
Today, ADNOC is improving the conventional efficiencies in hydrocarbon production by injecting carbon dioxide,CO2, captured at its Al Reyadah facility into some of Abu Dhabi’s oil fields to boost oil production in EOR. Gazprom Neft has a successful track record of utilizing cutting-edge EOR techniques, including polymer and surfactant flooding.
ADNOC and Gazprom Neft have also agreed to evaluate collaboration opportunities in production analytic systems for integrated operations in both Upstream and Downstream using artificial intelligence, as well as other areas across the value chain, with the goal of helping both companies to unlock greater value and drive efficiencies.
Dr. Al Jaber said: "This comprehensive framework agreement with Gazprom Neft is a natural evolution of the close and deep bilateral relations between the UAE and Russia, and provides a foundation to strengthen and expand the strategic energy relationship between both countries. It also further demonstrates how ADNOC is leveraging world-class partnerships to create, unlock, and maximize value from our substantial assets and resources for the benefit of the UAE and our partners.
"The strategic agreement offers the potential for exciting new opportunities for both companies, in the Upstream and Downstream sectors, as well as in artificial intelligence and sour gas where ADNOC has vast untapped reserves. It is our firm hope that we can convert this framework agreement into a new, mutually beneficial partnership that will create long-term and sustainable value."
The framework agreement will allow ADNOC and Gazprom Neft to combine and leverage their deep technological and operational expertise in various fields and marks another step in ADNOC’s expanded approach to strategic partnerships and co-investments as it creates a more profitable upstream, a more valuable downstream and a more sustainable and economic gas supply.
Mr. Baryshnikov said: "The Strategic Framework Agreement concluded between Gazprom Neft PJSC and ADNOC marks a major milestone in the developing relationship between our two companies. It creates a platform for cooperation in Research and Development as well as Upstream and Downstream sectors. I have every confidence that our expertise and resources, pooled together, will contribute to strengthening the positions of both companies in the oil and gas market. Moreover, our partnership builds capacity to deliver breakthrough solutions that can be used to achieve the goals of Gazprom Neft technology strategy and to overcome the challenges confronting the industry."
Gazprom Neft is primarily engaged in oil and gas exploration and production, refining, and the production and sale of petroleum products. It is one of the world’s top ten public companies by proven liquid hydrocarbon reserves, and a global leader in its rapidity in reserves replacement.
The company’s production and refining volumes – which in 2018 reached 92.9 million tonnes of oil equivalent,mtoe, and 42.9 million tonnes of oil, respectively – place it among the top three most important companies in Russia. Its products are sold throughout Russia and exported to over 50 countries worldwide.
Has the peak of the shale revolution come and gone?
The shale revolution transformed the United States into the world’s biggest producer of oil and natural gas in a little more than a decade. But now the industry is facing the prospect that the shale boom has peaked and the best days are behind it as drilling activity declines, jobs dwindle, and many of the prime oil-producing spots are depleted.
Shale’s future is still a matter of debate, but there’s little doubt the energy sector has suffered through a weak 2019 with a more challenging 2020 on the horizon amid middling oil prices, abundant supplies, rising bankruptcies, growing climate change concerns and historically low Wall Street sentiment. The trends are dire enough that energy analysts at the New York investment research firm Evercore ISI this month declared, “The oil ‘shale revolution’ is over. Finally.”
The U.S. shale sector stubbornly persevered through the brutal oil bust that started in late 2014, returning to growth mode two years later. But since the end of 2018, drilling activity has steadily declined, with the number of operating rigs plunging 20 percent nationally over the past year. The rig count in the heart of the shale boom, the Permian Basin in West Texas, is down 15 percent.
“It appears we’ve already peaked,” said Evercore ISI analyst James West. “Investors are damn near catatonic. U.S. shale is not a panacea for production growth. It’s quickly coming to a close.”
Doom and gloom
West and other analysts argue that shale was always unprofitable for most companies as they burned through billions of dollars from investors and lenders to expand rapidly, then failed to deliver returns. As a result, the industry drove production to record levels — but at the cost of losing investors and access to capital.
A steady flow of capital is particularly vital for developing shale fields, which require an endless treadmill of drilling. After initial bursts of large volumes of crude, the wells deplete faster than conventional wells, requiring the constant drilling of new wells to keep up production.
On HoustonChronicle.com: Ominous signs ahead for oil prices, industry
Doug Terreson, another Evercore ISI analyst, compared the dynamic to the Red Queen’s warning to Alice in Lewis Carroll’s “Through the Looking-Glass”: “It takes all the running you can do, to keep in the same place. If you want to get somewhere else, you must run at least twice as fast as that!” Ultimately, Terreson and West contend, shale drillers will be more active in the state of Delaware — where many firms file for bankruptcy — than in the Delaware Basin, the Permian’s still-booming western lobe.
Not everyone sees it that way. Oil and gas companies continue to find new ways to innovate, reduce costs and produce more oil with fewer rigs and people.
The Permian is now the world’s largest oilfield. And the country’s top three shale fields — the Permian, the Eagle Ford in South Texas and the Bakken in North Dakota — easily account for more than half of the nation’s record oil production of about 12.5 million barrels a day.
“I don’t think you would use boom to describe shale right now, but it’s certainly not a bust,” said Andrew Dittmar, an analyst with Enverus, an Austin energy research firm. “Some are expecting the death of shale in its entirety, and I don’t think that’s remotely true.”
Shale’s Texas birth
George P. Mitchell drilled his first successful shale well more than 20 years ago in the Barnett shale near Fort Worth. After many years of trial and error, success came from combining the decades-old technologies of hydraulic fracturing, called fracking, with horizontal drilling to crack open the shale rock and release natural gas. Mitchell eventually sold his company in 2002 to Devon Energy of Oklahoma City for more than $3 billion.
The shale boom really started to take off in 2006, initially focusing on natural gas as it spread from the Haynesville shale in East Texas and Louisiana to the Eagle Ford shale. Outside of Texas, the Marcellus shale in Pennsylvania and the Bakken also took off.
As the shale revolution shifted from gas to crude oil earlier in this decade, the focus turned to the Permian Basin, triggering a new land rush in West Texas and southeastern New Mexico. But rapid growth is leading to diminishing returns for many companies as the most prolific oil reservoirs are drained and newer wells prove less productive.
Oil companies have responded by drilling longer horizontal wells — some extending more than three miles — and vastly increasing the amount of water and sand pumped into wells at high pressures crack shale to release oil and gas. But most industry analysts believe that productivity per foot of well has peaked — or is close to peaking — and will begin to decline.
Companies also have responded by drilling more wells in closer proximity, which has created new challenges in determining how to space the wells. Drill them too far apart and the operators risk leaving oil in the ground. If they’re too close, one well can bleed into the other, vastly diminishing the value of the second well.
On HoustonChronicle.com: Texas’ most dangerous border leads to New Mexico
The Dominator project of the Midland oil and gas company Concho Resources is a case in point. Concho drilled 23 wells too closely together on its Permian acreage, resulting in volumes more than 30 percent below expectations.
Shale pioneer Mark Papa, who previously led Houston’s EOG Resources and now heads the Colorado company Centennial Resource Development, used a baseball analogy to describe the state of the shale industry — “Probably in the seventh inning of a nine-inning game.”
While production from the Permian is expected to keep rising as world’s biggest oil companies — including Exxon Mobil, Chevron, Royal Dutch Shell and BP — gobble up acreage and smaller companies, output has nearly plateaued in the Eagle Ford and Bakken. Oklahoma’s SCOOP and STACK shale plays and Louisiana’s Austin Chalk have disappointed thus far.
Wyoming’s Powder River Basin appears to have promise, but it’s no Permian.
The coming transition
The days of $100 per barrel oil, a level last reached in 2014, are over, analysts said, but the industry has evolved, gained efficiencies and learned to profit with crude above $60 per barrel. But after rising for the better part of two years, oil prices have fallen and remain stuck between $50 and $60 per barrel, lately closer to $50. Some companies can make money at those prices; many can’t.
The pressure on oil prices is mostly downward — barring major breakthroughs in U.S. trade wars. Oil production is rising even as global economic growth and energy demand weakens, leading analysts to forecast that oil may fall below $50 in 2020 and stay there through much of the year. Few companies can make money at those prices.
“We’re going to go through a pretty painful transition period for the next year or two,” said Matt Portillo, managing director of exploration and production research at Tudor, Pickering, Holt & Co., a Houston investment bank.
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Shale capital spending already has fallen an average of about 8 percent this year, according to Tudor, Pickering, Holt, and Co., and could fall up to another 25 percent next year. Layoffs would abound from the West Texas oilfield to the white-collar corporate centers in Houston. They’ve already started. Texas has shed about 5,000 oil and gas jobs over approximately the past three months, according to the Texas Workforce Commission.
“We’re going to go through a pretty painful transition period for the next year or two,” Portillo said.
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Thailand Energy Minister Sontirat Sontijirawong ordered state-owned oil and gas major PTT last week to accelerate its gas business so that the country can become a liquefied natural gas (LNG) trading hub in Southeast Asia.
He said the government would support PTT's gas business at the regional level and the country’s Energy Regulatory Commission (ERC) would ease related regulations for LNG import and re-export.
"PTT is capable of becoming a regional [LNG] trader because the company is heavily invested in gas infrastructure and human resources," Sontirat said.
"The company is studying the feasibility of the LNG trading business, expecting to reach a conclusion in a couple of months. The business plan will be proposed to the National Energy Policy Council in December."
PTT also unveiled a plan last month to provide small-scale LNG distribution to marine vessels and heavy-duty trucks in the region, development of a gas pipeline and feeding LNG to a power generation system.
PTT also has two innovative projects for LNG distribution selected to join the ERC plan for testing before commercial adoption.
The International Gas Union defines small-scale LNG (SSLNG) as any facility with a liquefaction and regasification capacity of 0.05–1.0 million metric tons/year (mmty) and vessels with a capacity of 60,000 cubic meters or less.
Sontirat’s statements come less than two weeks after The Industrial Estate Authority of Thailand said it had signed an agreement worth $1.33 billion with Gulf MPT LNG Terminal Co. to build the country’s third LNG import terminal.
PTT operates the country’s only LNG import facility, the Map Ta Phut LNG project, southeast Asia’s first LNG import terminal. It has a regasification capacity of 11.5 mmty. The company is also increasing loading facilities at the project. The company also constructing the new Nong Fab LNG import terminal in Rayong. The terminal is expected to have a regasification capacity of 7.5 mmty and become operational by 2022.
With a total capacity of 19 mmty by 2022, and around 24 mmty with the completion of the first phase of its third LNG facility, Thailand could capture considerable LNG market share as both a reseller and provider of the fuel in southeast Asia, particularly as neighboring southeast Asian tiger economies, including Vietnam, the Philippines, Bangladesh and possibly Cambodia, will bring LNG import facilities onstream within the next few years and will be looking for shorter term, flexible supply deals. These countries are also proposing small to mid-sized LNG to power facilities that would also help PTT develop its LNG trading business model.
Small-scale opportunities
Because many smaller outlying islands in the Asia-Pacific region, including hundreds of stranded islands in archipelago countries like the Philippines and Indonesia, as well as islands offshore Myanmar, are still using aging oil-fired power plants to supply electricity, Thailand’s push for LNG distribution to neighboring countries could help the region transition to more efficient and cleaner gas-fired power usage, in addition to providing more demand for large LNG producers that could still be struggling with a supply overhang of the fuel up to the mid-part of the next decade.
LNG is also increasingly replacing high sulfur fuel oil for marine vessels which would also help reduce greenhouse gas emissions. Southeast Asia could also follow the lead of the United States and China by using LNG as a fuel for the long-haul trucking sector.
There are several advantages of using SSLNG, including quicker buildout time, being less capex intensive, and providing more flexibility on logistics and transportation.
The increase of SSLNG development could also benefit from the recent drop in spot prices for LNG in Asia, which are at multi-year lows amid warmer temperatures in North Asia (home to around two-thirds of global LNG demand) and more supply hitting the market, particularly from the United States. The ongoing supply overhang is projected to last until at least 2022 with some analysts forecasting the glut to persist even longer. As long as LNG prices remain competitive or even below oil price equivalency, this price differential will help boost interest in SSLNG.
However, SSLNG is not without unique headwinds, such as supply chain optimization, training large numbers of people skilled in handling LNG, and trying to accurately predict future demand in remote areas, according to the Asian Pacific Energy Cooperation. The complexity of its value chain also makes its cost per unit more expensive. Also, the different nature of SSLNG supply chain as compared to the traditional large scale LNG supply chain suggests that new business models are needed for players in the SSLNG market, Enerdata said in a report.
SSLNG is projected to grow globally across various sectors. French energy giant Engie forecasts that global demand for SSLNG by 2030 will steadily increase, including 24 mmty in the power sector, 57 mmty in the marine fuel sector and around 85 mmty in the LNG trucking sector.
U.S. oil and gas employment has started to fall as the sector contracts in response to lower prices over the last year – and further job losses are likely in the next few months as the rate of well drilling declines further.
In 2017/18, the second shale-oil boom created almost 100,000 new high-paying jobs in oil and gas drilling as well as associated services such as site preparation, cementing, casing and pressure-pumping.
Employment gains in the oil and gas sector also helped support tens of thousands more jobs along the supply chain including trucking, accommodation, retail and leisure services.
The impact was felt intensively in some local areas – especially those overlaying the oil- and gas-rich Permian Basin in western Texas and eastern New Mexico.
Non-farm employment in the Midland metropolitan area at the heart of the Permian in Texas surged at an annual rate of 15% in the first nine months of 2018, data from the U.S. Bureau of Labor Statistics shows.
Non-farm jobs in the Odessa metro area, another Permian boom town, were up more than 10% in the first three quarters of 2018 compared with a year earlier (“Current employment statistics”, BLS, Oct. 4).
But the persistent slump in oil prices since the start of October 2018 has brought job creation to a halt and replaced it with a gradual but steady trickle of layoffs
LAYOFFS
Nationwide, the number of jobs at companies providing support services to the oil and gas industry, including site preparation and construction, has fallen progressively over the last year.
Employment in oil and gas support activities, subsector 213112 in the North American Industry Classification System, had fallen by 14,000 or 5% between its cyclical peak in October 2018 and August 2019.
Job losses have coincided with the downturn in activity shown in weekly drilling reports from oilfield services company Baker Hughes, but more job losses could still be on the way.
Since November 2018, the number of rigs drilling for oil has fallen by 176 (20%) and for gas by 51 (26%), according to Baker Hughes. Job losses have been much smaller, so far.
Oilfield services companies have kept busy completing the large inventory of oil and gas wells inherited from 2018 and putting them into production.
Delayed completions of wells originally drilled in the second half of 2018 and early 2019 have largely sustained oilfield employment and ensured oil and gas output continues rising.
But the downturn in well drilling has started to filter through to fewer completions in recent months, which will put more pressure on jobs and production.
Completion rates for oil and gas wells fell every month between April and August, according to the U.S. Energy Information Administration (EIA).
Even so, completions are still outpacing the number of new wells drilled, with the result that the inventory of drilled but uncompleted wells is shrinking.
The number of drilled but uncompleted holes shrank by 536 (11%) between January and August, according to the EIA (“Drilling productivity report”, EIA, Sept. 16).
Even if drilling rates fall no further, completion rates seem likely to decelerate more, which will cut employment and slow production growth.
Employment losses in oil and gas will hit local job markets hard, especially where local firms had expanded expecting a continued boom (“Cheap hotel rooms in Texas are a bad sign for frackers”, Bloomberg, Sept. 26).
The entire oil and gas supply chain and job market will remain under pressure until the global economic outlook improves and oil consumption growth returns closer to its long-term trend rate.
Oil and gas producer Occidental Petroleum nudged its estimate for third-quarter production higher on Tuesday, helped by fewer shutdowns in Colorado’s DJ basin and strong performance in its Permian Resources unit.
The shale producer, which completed the purchase of rival Anadarko Petroleum in August, now expects production from continuing operations to be 1.1 million to 1.12 million barrels of oil equivalent (boe) per day.
The company’s initial forecast for combined pro-forma production from continuing operations was between 1.3 and 1.4 million boe per day but, adjusting for the close of the merger, it later lowered that to between 1.06 million and 1.10 million boe per day.
Houston, Texas-based Occidental also said it expects third-quarter domestic onshore realized prices to be $54.00 per barrel for oil and $1.20 per thousand cubic feet for natural gas.
Occidental’s merger with Anadarko closed on Aug. 8. The company is scheduled to report third-quarter results on Nov. 4.
State-owned Pakistan LNG has cancelled a tender to buy liquefied natural gas over a 10-year period and may turn to the spot market instead, two sources familiar with the matter told Reuters on Tuesday.
The company issued the tender in early June to import 240 LNG cargoes of 140,000 cubic metres each for delivery over 10 years for the country’s second LNG terminal.
But it has decided to cancel the tender due to inadequate demand for the super-chilled fuel, one of the sources said.
“(The company) has decided not to proceed with technical evaluation and opening of commercial offers as there is no demand against this tender,” the source added, declining to be identified.
“So for now, (the company) has decided to stop the process of long-term commitment until it receives long-term demand for LNG,” the source said.
Pakistan is expected to be a significant growth driver in global LNG demand with the cabinet recently approving five consortiums to progress with their LNG terminal plans.
Pakistan LNG’s cancelled tender had been keenly watched in the industry. The company was expected to publish the lowest prices offered by bidders, providing a valuable insight into the opaque LNG market, which is characterised by closed bilateral trades, private long-term supply agreements and an over-the-counter spot market.
Italy’s Eni, China’s PetroChina, Azeri state oil company SOCAR and commodities trader Trafigura had placed offers into the tender, sources had told Reuters.
Wall Street’s sudden realization regarding disappointing returns in the so-called “U.S. shale revolution” and Boeing’s turbulent market performance may appear to be unrelated examples of bad outcomes. Some may even argue there is zero correlation between the two. At a deeper level, however, the root causes are failures of poor risk management. This is evidence most recently and conspicuously in the disappointing results reported by many U.S. shale players. Ironically, the recent fires at Saudi Aramco’s giant processing facilities that wiped out six million barrels of daily production -- at least temporarily -- underscores the need to carefully gauge the future of U.S. oil.
The resurgence of U.S. crude productions to nearly 13 million barrels a day, driven by the shale revolution, is a phenomenal success story, a product of innovation, evergreen technologies and the country’s unique free-market attributes. Underneath this tale of accomplishment, however, lie disturbing patches of shortcomings in three aspects: lax engineering rigor, fuzzy financials, and focus on short-term results.
One set of well statistics in shale are most revealing. During the last decade more that one in three wells drilled in the Permian have been uneconomic at $60-per-barrel oil. The figures are not much better during the recent past – 2017 to present – based on analysis of publicly available data. For many companies in the bankruptcy domain, the statistics are even worse.
The data reflect lax engineering rigor and due diligence in the race to achieve short-term production gains and financial prominence. A 30% failure rate would be inadmissible in any other business, and so it should be in oil and gas.
From an investor’s perspective, the failures can be correlated with incomplete risk assessments focused mainly on crude price volatility issues, and disregarding some well known geological and engineering risk factors. One might also add that Wall Street’s overemphasis on cost-efficiency and short-term returns amplified the industry urge to undercut engineering rigor and oversight, highlighting the painful parallels with Boeing’s 737 Max failures.
Location, location, location is an overused term in real estate transactions. But the cliche holds true for oil and gas. Yet, for many, this was simply forgotten in the fast and furious world of shale. The hope is that catastrophic failures prompt much needed rigor for dramatic remedies. Similar to the way BP’s Macondo tragedy of April 2010 in the Gulf of Mexico spurred comprehensive improvements in offshore safety, the recent financial tremors in the Permian should set the stage for fundamental change – a return to an absolute emphasis on engineering rigor and disciplined planning, and long-term value over short-term gains.
Does change mean the end of the U.S. resurgence in the global energy arena? The ascendency of OPEC? Return to $100-per-barrel crude? The short answer is none of the above.
What we are likely to witness is an accelerating pace of consolidations among U.S. producers and service providers, accompanied by an increased pace of bankruptcies for less efficient entities. While vigilant capital discipline may temper the growth trajectory of U.S. domestic production, the U.S. production will continue to grow, albeit at modest rates, on the strength of its capacity to continually innovate and achieve higher levels of efficiency. This is the new normal.
Neither OPEC nor Russia is immune to the relentless pressures of extreme efficiency led by the U.S. shale revolution. Texas is the new OPEC might be an overstatement, yet it conveys an element of truth. On the other hand, Saudi Aramco, by pressing forward with privatization through its initial public offering and by showing it is energized to rebound its production to pre-damage levels, is raising the stakes for the rest of OPEC.
The U.S. shale revolution started as a black swan event in Texas by a trailblazing oil man, George Mitchell, merely two decades ago, yet its ultimate legacy will be defined by its success (or failure) in diligently managing risks. Engineering exceptionalism requires looking beyond short-term profits – a fact that should not be masked by the anxieties amplified by the Saudi fires. The U.S. can and should take a leadership role in reassuring markets that there will be no disruption to global energy supplies. It will take a collaborative effort among divergent partners – U.S., OPEC and Russia – at a time when U.S. politics are heightened and the Middle East at a boiling point.
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But as the late Robert F. Kennedy used to say, “What is the alternative?” A fair question to Presidential candidates.
Nansen G. Saleri is the chief executive and co-founder of Quantum Reservoir Impact and the former head of reservoir management for Saudi Aramco. He wrote this column for The Dallas Morning News.
Texas cities threaten to sue over Kinder Morgan pipeline, Edwards Aquifer endangered species
Austin, San Marcos and Kyle are joining two groups in a threat to sue Houston pipeline operator Kinder Morgan in a row over a proposed natural pipeline in the Texas Hill Country and eight endangered species found only in the Edwards Aquifer -- including the Texas Blind Salamander. less Austin, San Marcos and Kyle are joining two groups in a threat to sue Houston pipeline operator Kinder Morgan in a row over a proposed natural pipeline in the Texas Hill Country and eight endangered species ... more Photo: U.S. Fish & Wildlife Service Photo: U.S. Fish & Wildlife Service Image 1 of / 8 Caption Close Texas cities threaten to sue over Kinder Morgan pipeline, Edwards Aquifer endangered species 1 / 8 Back to Gallery
Citing concerns about seven endangered and threatened species found only in the Edwards Aquifer, the cities of Austin, San Marcos and Kyle have joined two groups in a threat to sue two federal agencies in order to stop Kinder Morgan's Permian Highway Pipeline from going through the Texas Hill Country.
Over the past week, leaders with the three cities have voted to join the Barton Springs Edwards Aquifer Conservation District and the Wimberley Valley Watershed Association in filing a notice of intent to sue the U.S. Fish and Wildlife Service and U.S. Army Corps of Engineers in order to halt Kinder Morgan's proposed Permian Highway Pipeline.
The $2 billion pipeline project is being designed to move 2.1 billion cubic feet of natural gas per day from the Permian Basin of West Texas to the Katy Hub near Houston. The proposed route takes the 42-inch pipeline through the picturesque Texas Hill Country, where the project faces stiff opposition.
Working with the Texas Real Estate Advocacy and Defense Coalition, or TREAD Coalition, the five opponents are citing concern over the pipeline and natural gas leaks affecting the Edwards Aquifer, which is home to the the Texas Blind salamander, Barton Springs salamander, the Austin Blind salamander, the San Marcos salamander, the Fountain darter, the Comal Springs dryopid beetle and the Comal Springs riffle beetle.
“It is beyond legitimate scientific dispute that Kinder Morgan’s construction and operation of its large pipeline through these sensitive areas will pose a serious threat to these aquifers and the endangered and threatened species that live there,” the TREAD Coalition's lead attorney William Eubanks said in a statement. “As a result, there are several legal obligations that the USACE, USFWS, and Kinder Morgan must satisfy to ensure compliance with the Endangered Species Act, Clean Water Act, and National Environmental Policy Act.”
Endangered Species: Pipeline opponents to sue over golden-cheeked warbler
Kinder Morgan officials are preparing a statement but the company has maintained that the pipeline route was carefully chosen to affect the fewest number of landowners. The company said it held several public meetings before moving forward with the project.
Under Texas state law, pipelines require an easement that must be kept clear. Kinder Morgan designed the proposed pipeline route to include a 600-foot-wide corridor that allows for some flexibility and adjustments.
The company contends the pipeline would generate nearly $1 billion annually to state and county governments and unlock production bottlenecks in the Permian Basin — allowing leaseholders to earn more than $2 billion in annual royalties for landowners, school districts and counties.
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The notice of intent to sue comes less than two weeks after the City of Kyle and Kinder Morgan reached a settlement in a dispute over anti-pipeline ordinance passed into law by city leaders. Retaining their right to sue the pipeline company in other matters, Kyle city leaders voted to join the notice of intent during a Tuesday evening meeting.
San Marcos city leaders held a similar vote on Tuesday evening while the City of Austin, the Barton Springs Edwards Aquifer Conservation District and the Wimberley Valley Watershed Association voted to join the notice of intent last week.
In April, opponents of the pipeline project sued Kinder Morgan, the Railroad Commission of Texas and five agency executives on state constitutional grounds but a state district judge ruled in favor of the pipeline project.
Read the latest oil and gas news from HoustonChronicle.com
China National Offshore Oil Corp (CNOOC) is working with a railway company to trial delivery of liquefied natural gas (LNG) by rail, a senior company executive said on October 15.
The two-year trial will involve sending LNG to central China from four terminals - Guangxi, Zhuhai, Zhejiang and Tianjin, Wang Si, head of the company's LNG ISO Tank Container Intermodal Transport Project, said in a conference.
China is the world's second largest importer of LNG but lacks natural gas pipeline and storage infrastructure.
While trucks carrying ISO tanks can serve distances of 500 kilometers, trains will serve longer distances of over 1,000 km, Wang said.
Each ISO tank can carry 17-18 tonnes of LNG and the trains will be able to take 50 such tanks, he said.
CNOOC, China's largest LNG importer, aims to transport 1 million tonnes per annum (Mtpa) of LNG using ISO tank containers over 2019-2021, increasing this to 2 Mtpa by 2022-2023, he added.
The trial is pending approval from China Rail Company, he said.
CNOOC also plans to use ISO tanks for LNG storage as they are about 30% cheaper than current storage facilities and save space, Wang said.
Australia’s No. 2 independent gas producer Santos Ltd on Thursday said third-quarter production and sales volumes peaked to record levels, benefiting from higher output from its Western Australia assets.
Revenue of $1.03 billion was the second highest quarterly sales on record, the company said in a statement, while production surged 32% to 19.8 million barrels of oil equivalent (mmboe), beating an estimate of 18.9 mmboe by UBS.
“Another highlight of the quarter was the successful appraisal of the Dorado field which is one of the most exciting growth projects in our portfolio. Following the strong well test results, we are targeting FEED-entry in early 2020,” Santos Chief Executive Officer Kevin Gallagher said.
Dorado is Australia’s biggest oil find since 1996 and Santos owns 80% of the field, a stake it came to own with its acquisition of Quadrant Energy in 2018. Smaller peer Carnarvon Petroleum holds the remaining stake in Dorado.
Just days ago, Santos further consolidated its position in the global gas market by acquiring the northern Australian business of ConocoPhillips in a $1.39 billion deal. The deal is expected to add to Santos’ output by 25%.
The 65-year-old Adelaide-based company maintained its full-year production and sales forecast at 73-77 mmboe for production and 90-97 mmboe for sales.
By Scott DiSavino and Sabina Zawadzki
NEW YORK/LONDON, Oct 17 (Reuters) - A gap is emerging in the U.S. liquefied natural gas (LNG) industry as big players such as Exxon Mobil Corp and Cheniere Energy Inc race ahead to build export terminals without new long-term contracts, while smaller developers struggle to find financing for their first plants.
LNG trade has traditionally been underpinned by long-term purchasing deals which finance multi-billion dollar terminals that liquefy natural gas by chilling it to -260 degrees Fahrenheit (-160 Celsius), load it onto ships, and regasify it when delivered.
This is changing. As the market grows and pricing mechanisms diversify, some buyers do not want to commit to 20-year contracts. The growing prowess of oil majors such as Exxon and recent entrants such as Cheniere and trading houses means there are aggregators that can supply buyers more flexibly, making it harder for smaller players.
"The industry is moving away from long-term agreements to justify construction of a new facility to a true commodity business," said Charif Souki, co-founder and Chairman of Tellurian Inc.
Dozens of LNG export terminals are being planned in the United States with a total capacity exceeding 300 million tonnes per annum (mtpa). That is equal to the world's entire consumption of LNG last year. Globally, LNG demand is expected to rise 26% by 2024, far short of such an increase in export capacity, analysts said.
"I'm not going to pick a winner or loser here, but I don't think there is enough support for all of these projects by any means," said Rich Redash, head of global gas planning, at S&P Global Platts Analytics.
Tellurian has been seeking investors for its 27-mtpa Driftwood export terminal in Louisiana. Instead of trying to line up long-term purchase agreements, it offers customers the opportunity to invest in the company's gas production, pipelines and liquefaction.
The company has delayed the start of construction to early next year from a previous target of the first half of this year, according to company presentations. It also reduced how much its partners need to invest in the project to receive LNG to $500 per tonne from a previous target of $1,500 per tonne.
By contrast, Exxon and Qatar Petroleum decided this year to move ahead with their 15-mtpa Golden Pass project in Texas, while Cheniere said it would expand its Sabine Pass terminal in Louisiana. Neither were directly supported by substantial long-term agreements.
DELAYS
Buyers have been wary of committing to long-term deals due to the influx of flexible supply and the recent decline in prices, removing the urgency they felt last year to sign deals.
"It's hard to sign long-term deals when prices are so low," Vivek Chandra, CEO of Texas LNG, told Reuters. "I think to sign deals on long term basis is counterproductive now."
Texas LNG already delayed its Final Investment Decision (FID) from 2019 to 2020, but Chandra said that decision may slip further.
"We think our FID will be the end of next year, but we’ll see, we’re not under pressure, which is good," he told Reuters.
U.S. developers had been banking on signing deals with buyers in China, which will account for more than 40% of global gas consumption growth between 2018-2024, becoming the top LNG buyer by 2024.
The 15-month U.S.-China trade war has choked off overall demand from that country, once the third biggest buyer of U.S. LNG. For the first eight months of 2019, the United States exported just 14% of the volumes it sent to China for the same period in 2018, according to U.S. Department of Energy data.
"It is still a very difficult market. The trade war with China has put a damper on deals in China," said Greg Vesey, CEO of soon-to-be U.S.-listed LNG Ltd, which is planning the 8.8-mtpa Magnolia project in Louisiana.
Magnolia had hoped to reach a FID last year but delayed that citing the trade war. It has about 25% of its capacity under long-term contract. Vesey said there is potential LNG Ltd could make a FID this year but next year would be more likely.
Other delays include two Louisiana projects: Delfin LNG's floating plant and Energy Transfer LP's Lake Charles LNG, both asked federal regulators for more time to complete.
Large projects from other countries are also vying for market share, including Russia's Arctic LNG 2 and two projects in Mozambique being shepherded, respectively, by Total SA and Exxon.
(Reporting by Scott DiSavino in New York, Sabina Zawadzki and Ekaterina Kravtsova in London and Jennifer Hiller in Houston; Editing by David Gregorio)
https://finance.yahoo.com/news/big-u-liquified-natgas-players-050000455.html
Working gas in underground storage, Lower 48 states Summary text CSV JSN Historical Comparisons Stocks
billion cubic feet (Bcf) Year ago
(10/11/18) 5-year average
(2014-18) Region 10/11/19 10/04/19 net change implied flow Bcf % change Bcf % change East 880 854 26 26 809 8.8 871 1.0 Midwest 1,044 1,009 35 35 903 15.6 1,007 3.7 Mountain 205 203 2 2 177 15.8 207 -1.0 Pacific 296 296 0 0 264 12.1 320 -7.5 South Central 1,093 1,054 39 39 874 25.1 1,101 -0.7 Salt 246 229 17 17 201 22.4 290 -15.2 Nonsalt 847 825 22 22 672 26.0 811 4.4 Total 3,519 3,415 104 104 3,025 16.3 3,505 0.4
Totals may not equal sum of components because of independent rounding.
Summary
Working gas in storage was 3,519 Bcf as of Friday, October 11, 2019, according to EIA estimates. This represents a net increase of 104 Bcf from the previous week. Stocks were 494 Bcf higher than last year at this time and 14 Bcf above the five-year average of 3,505 Bcf. At 3,519 Bcf, total working gas is within the five-year historical range.
For information on sampling error in this report, see Estimated Measures of Sampling Variability table below.
iShares U.S. Oil & Gas Exploration & Production ETF, formerly iShares Dow Jones U.S. Oil & Gas Exploration & Production Index Fund (the Fund), is an exchange traded fund. The Fund seeks investment results that correspond generally to the price and yield performance of the Dow Jones U.S. Select Oil Exploration & Production Index (the Index). The Index measures the performance of the oil exploration and production sub-sector of the United States equity market, and includes companies that are engaged in the exploration for and extraction, production, refining, and supply of oil and gas products. The Fund invests in a representative sample of securities included in the Index that collectively has an investment profile similar to the Index. Due to the use of representative sampling, the Fund may or may not hold all of the securities that are included in the Index. The Fund's investment advisor is BlackRock Fund Advisors.
Basic Details Issuer iShares Fund NameiShares U.S. Oil & Gas Exploration & Production ETF Tax ClassificationRegulated Investment Company SymbolBATS:IEO Inception Date5/1/2006 Fund ManagerDiane Hsiung, Jennifer Hsui, Greg Savage, Alan Mason http://www.iShares.com/ Web Phone+1-800-4742737 Fund Focus Asset ClassEquity BenchmarkDow Jones US Select Oil Equipment & Services Index CategorySector FocusEnergy Development LevelDeveloped Markets RegionNorth America Fund Statistics Assets Under Management$205.68 million Average Daily Volume$120,405.30 Discount/Premium0.03% ETF Expenses Management Fee0.44% Other Expenses0.00% Total Expenses0.44% Fee Waiver0.00% Net Expenses0.44% Administrator, Advisor and Custodian AdministratorState Street Bank and Trust Company AdvisorBlackRock Fund Advisors CustodianState Street Bank and Trust Company DistributorBlackRock Investments, LLC Transfer AgentState Street Bank and Trust Company Trustee Lead Market MakerLatour Trading IEO Rates by TradingView Receive IEO News and Ratings via Email Sign-up to receive the latest news and ratings for IEO and its competitors with MarketBeat's FREE daily newsletter.
MarketBeat Community Rating for iShares U.S. Oil & Gas Exploration & Production ETF (BATS IEO)
Community Ranking: 2.4 out of 5 ( ) Outperform Votes: 31 (Vote Outperform) Underperform Votes: 33 (Vote Underperform) Total Votes: 64
MarketBeat's community ratings are surveys of what our community members think about iShares U.S. Oil & Gas Exploration & Production ETF and other stocks. Vote "Outperform" if you believe IEO will outperform the S&P 500 over the long term. Vote "Underperform" if you believe IEO will underperform the S&P 500 over the long term. You may vote once every thirty days.
NEW YORK & HOUSTON--(BUSINESS WIRE)--A fund managed by Basalt Infrastructure Partners II GP Limited (“Basalt”) today announced that it has entered into a definitive agreement to acquire Third Coast Midstream LLC’s natural gas transmission business (the “Natural Gas Transmission Business”).
“This investment represents a rare opportunity to invest in a portfolio of demand-driven, regulated 'last-mile' natural gas pipelines serving utilities and other key end-user customers in the Southeastern United States. The business is strategically positioned to capture continued industrial growth in the region,” said David Greenblatt, Partner of Basalt Infrastructure Partners LLC, exclusive investment Advisor to the Basalt funds. “Cash flows from the business are anchored by long-term firm transportation contracts with a diverse customer base of utility, power and industrial customers.”
"We are proud of the accomplishments our team has executed over the last several years in building out this portfolio of high-quality gas transmission assets in the Southeast United States," stated Matt Rowland, Third Coast's President and Chief Executive Officer. "We are confident that Basalt brings the right combination of financial strength and strategic experience to continue safe, efficient and growing operations. The sale is a further step in Third Coast's strategic repositioning to focus on its core Gulf of Mexico infrastructure platform."
The Natural Gas Transmission Business includes 7 regulated natural gas lateral pipelines with total capacity of over 1,600 MDth per day, stretching approximately 550 miles. The lateral pipelines are connected to 8 major long-haul pipelines, ensuring reliable gas supply to customers across Louisiana, Alabama, Mississippi, Tennessee and Arkansas.
Consummation of the transaction remains subject to customary closing conditions, including expiration or termination of applicable regulatory waiting periods. The terms of the transaction are not being disclosed.
Barclays served as exclusive financial adviser to Basalt and Vinson & Elkins served as its legal adviser. RBC Capital Markets served as exclusive financial adviser to Third Coast and Orrick served as its legal adviser.
About Basalt
Basalt manages an infrastructure equity investment fund focusing on investments in utilities, power, transport, and communications infrastructure in the United States, Canada and Europe. This acquisition will represent Basalt’s ninth investment in the second flagship Basalt fund. Other investments by the second flagship Basalt fund include DB Energy Assets, Helios Power and Detroit Thermal in the United States, and North Star, Mareccio Energia, Caronte and Tourist, Manx Telecom, and Connect Fibre in Europe.
For more information, please visit www.basaltinfra.com.
About Third Coast
Headquartered in Houston, Texas, Third Coast Midstream, LLC is a full-service midstream company with assets that provide critical midstream infrastructure linking producers of natural gas, crude oil, NGLs, and condensate to end-use markets. Third Coast’s assets are strategically located in some of the most prolific offshore basins in the Deepwater Gulf of Mexico and onshore basins in the Eagle Ford and East Texas. Third Coast currently owns or has an ownership interest in approximately 5,100 miles of interstate and intrastate pipelines, as well as ownership in gas processing plants, fractionation facilities, an offshore semi-submersible floating production system with nameplate processing capacity of 90 MBbl/d of crude oil and 220 MMcf/d of natural gas, and a terminal site with approximately 3.0 MMBbls of storage capacity.
For more information, please visit www.3CMidstream.com.
Houston-based Carrizo Oil & Gas Inc., in the midst of a contentious takeover by cross-town operator Callon Petroleum Co., said its Texas-focused production during the third quarter climbed 6% sequentially and it also took advantage of a brief oil price rally during September to add to 2020 hedges.
In a preliminary report ahead of third quarter results, Carrizo said quarterly production volumes are forecast to be 69,500-69,600 boe/d, a 6% sequential increase. Carrizo’s primary operations are in the Eagle Ford Shale and Permian Basin.
Oil production is expected to account for around 66% of output, while natural gas should account for 18% and natural gas liquids production at about 16%.
The independent, whose primary focus is the Permian Basin and Eagle Ford Shale, said it also took advantage of an uptick in oil prices during September to boost its 2020 hedge position.
Hedges were covering 10,000 b/d of oil for 2020, consisting of three-way collars with an average floor price of $55.00/bbl, ceiling price of $64.10/bbl and subfloor price of $45.00/bbl.
The total hedge position for 2020 now stands at 25,000 b/d, including swaps covering 3,000 b/d of crude oil at an average fixed price of $55.06 and three-way collars covering 22,000 b/d with an average floor price of $55.34, ceiling price of $65.16 and subfloor price of $45.34.
Carrizo in July agreed to tie-up with Permian pure-play Callon Petroleum Co. valued at $3.2 billion. However, some Callon shareholders are not enthused by the deal, questioning the value of acquiring Carrizo’s “inferior” Eagle Ford assets.
If approved, Callon shareholders would own 54% of the combined company, with Carrizo shareholders holding the remaining stakes.
TC Energy, formerly known as TransCanada, has declared force majeure on the Keystone oil pipeline after a snow storm in Manitoba disrupted operations, Reuters reports, citing a confirmation from the pipeline operator.
“Due to the recent storm in Manitoba over the weekend, we did declare force majeure as the province declared a state of emergency. We are currently operating at reduced flows,” a spokesperson for TC Energy told Reuters in a statement.
The Keystone pipeline has a capacity to carry 590,000 bpd of Canadian crude to the United States refineries. While it is unclear exactly how much TC Energy had reduced the flow of oil through the pipeline, but Western Canadian Select was down on the news, extending a losing streak.
The Keystone pipeline is one of the few vital outlets for Canadian crude and any disruption in its operation is bound to affect prices sharply due to the lack of alternative outlets.
What’s more, Canadian oil prices already came under new pressure last month, when the Alberta government announced it would relax production cuts imposed last December, allowing local oil companies to produce 3.8 million barrels of crude daily in November.
The cuts were imposed by the previous Alberta government in an attempt to arrest a catastrophic collapse in prices because of the growing imbalance between production and export capacity. The cuts did what they were supposed to do and prices rebound quickly. Since then, these have been lowered a few times despite the problems around pipelines persisting.
Even so, Albertan drillers got some good news in September. First, the federal government said work was about to resume on the Trans Mountain pipeline—the infrastructure that many producers are pinning their hopes for the future on—and it should be operational by 2022, at a daily capacity equal to that of the Keystone pipeline.
More good news came from across the border, where a Nebraska court finally approved the alternative route for the Keystone XL pipeline—a project even more controversial than Trans Mountain.
By Irina Slav for Oilprice.com
More Top Reads From Oilprice.com:
Asian spot prices for liquefied natural gas (LNG) rose to an eight-month high this week as demand for cargoes emerged ahead of winter.
Spot prices for December delivery to Northeast Asia are estimated to be about $6.80 per million British thermal units (mmBtu), up 35 cents from last week, said several sources who are market participants.
Prices for November delivery are estimated to be about $5.90 per mmBtu, up 10 cents from the previous week, they added.
Commodities trader Vitol bought a cargo for delivery over Dec. 13 to 17 from Gunvor during the S&P Global Platts pricing process on Thursday, at $7.10 per mmBtu, according to data from Platts.
Brunei LNG likely sold an early December loading cargo to Shell at $6.50 to $6.70 per mmBtu, industry sources said, although this could not immediately be confirmed.
Maintenance in Australia and an issue at a U.S. LNG plant at a time when South Korean buyers are looking for spot cargoes ahead of winter helped boost prices, trade sources said. High freight rates are also supporting cargo prices, they added.
Korea Gas Corp (KOGAS) is seeking LNG cargoes for December and January delivery after making a purchase for delivery in November, trade sources said. China’s Guangdong LNG is also importing cargoes for winter, a second source said.
On the supply side, train 1 at the Chevron Corp-operated Gorgon LNG export plant is undergoing maintenance, a company spokesman said earlier this week.
The work is expected to last until Nov. 29, which is expected to curb exports from Australia.
In the United States, exports from the Corpus Christi export terminal in Texas may have reduced due to an unidentified issue, but they are expected to resume soon, industry sources said.
“Feedgas has increased and flaring is indicating that it should be online soon,” one of the sources said.
Still, supply is adequate and is likely to cap gains in prices, traders added.
Several LNG tankers laden with LNG are currently floating globally, with traders anticipating winter demand to pick up.
Nigeria LNG has offered a cargo for early November loading in a tender that is expected to be awarded on Friday, while Russia’s Novatek likely sold four Yamal cargoes for delivery over December to March on a delivered ex-ship basis, an industry source said.
Commentary: Non-traditional energy companies lead a record year for corporate investment in energy start-ups
More money than ever is going to energy venture capital deals, but spread across fewer start-ups. This needs to change if venture capital is to have a significant impact on energy transitions.
Among the many takeaways from the UN Climate Action Summit earlier this week was the need for capital to be reallocated to clean energy solutions around the world – The Economist talks of the Climate Capitalists who see the golden lining in the climate cloud.
These investors can play a crucial role in bridging the gap between lab and market, for example via venture capital (VC) funding that enables entrepreneurs to commercialise their first low-carbon products and hone their business models. Among the companies that have had a boost from venture funding, some are reshaping the energy landscape. Tesla has been at the vanguard of creating today’s USD 80 billion market for electric cars. BBOX and its peers have turned off-grid renewables into a highly competitive sector. Risk-taking capital like VC is an essential complement to government and corporate research dollars.
But how much of this investment is actually happening? World Energy Investment 2019 has already looked at companies that are allocating revenue to investments in energy technology start-ups. Now that we have added the results for the first half of 2019 to our improved and updated database of investors, we see that companies have already invested a record level in energy technology start-ups in 2019, more than in any year since the “cleantech boom” from 2005 to 2012. Some of this is Corporate Venture Capital (CVC), which is the subset of early-stage VC activity that comes directly from large companies in related sectors, and not from dedicated VC funds or financiers. Some of it is later-stage investing, such as corporate-led private equity or acquisitions.
Importantly, these investments in energy technology start-ups are not just coming from energy companies. More money is flowing from corporate investors from the transport and information and communication technology (ICT) sectors in particular.
The growing presence of these firms in the development of energy technologies reflects a blurring of the boundaries between “traditional” and “non-traditional” energy companies, largely driven by the types of new technologies that are expected to shape our energy future. Digital sensors, batteries, electric vehicles and smart algorithms are among the main recipients of the more than USD 4 billion of deals in 2019. This is more than all of 2018 and nearly three times more than the average over 2012-15, before the current uptick began.
Companies inside and outside the energy sector are increasingly using corporate venture capital investments as part of a flexible and more open energy innovation strategy. As we’ve noted previously, there are several reasons large established companies provide capital to early-stage technology companies.
For example, the purpose of an investment might be to learn about a technology, acquire human capital, or build a relationship with the owner of the technology. This approach can cost less and involve less risk than developing a technology in-house, especially if the technology landscape is uncertain, as it is today in many parts of the energy system. This approach is often used with technologies that are outside the core competence of the corporate investor but that could potentially add significant value to existing businesses.
However, the most recent data reveals that the earliest, and riskiest stages of corporate venture capital represent a declining share of the total deal value. In fact, Seed, Series A and Series B funding was just 10% of total corporate spending in 2019, with the rest made up of growth equity, late-stage equity and even buy-outs.
Examples of these later stage deals include: Chevron and BHP’s investment in Carbon Engineering, an atmospheric CO 2 removal firm; Johnson Controls’ investment in Carbon Lighthouse, a smart energy efficiency service; Suncor’s investment in Enerkem, a waste-to-biofuel company; VW, Siemens, Vestas and Vattenfall’s investments in Northvolt, a battery producer; Hyundai, Kia and Porsche’s investments in Rimac Automobili, an electric sports car company; Ford and Amazon’s investment in Rivian, a maker of electric vehicles; Daimler and Amperex’s investments in Sila Nanotechnologies, a battery materials company; and BP’s investment in Solidia, a low-carbon concrete developer. In addition, there evidence that major energy companies are building capacity in new areas not only by taking stakes in innovative firms but also, increasingly, by acquiring them. In 2019, Shell acquired virtual power plant, home battery and electric vehicle charging companies. Others, like Centrica, continue to build portfolios of consumer-facing companies with software expertise.
While corporate entities are investing mostly in later-stage deals overall, traditional energy companies are playing a larger role in riskier early-stage CVC deals. Roughly half of CVC activity for energy start-ups in 2019 has come from the oil and gas, utilities and electricity equipment sectors.
Examples of these earlier stage deals include: BP’s investment in Belmont Technology, an artificial intelligence provider for oil and gas exploration; Comcast’s investment in Dandelion Energy, a geothermal provider; Eni’s investment in Form Energy, a long-duration electricity storage developer; Total and Equinor’s investment in Level10 Energy, a renewables marketplace; NTT Docomo and Statkraft’s investment in Metron Labs, an energy analytics platform; APICORP and Equinor’s investment in Yellow Door energy, a solar leasing firm; Iberdrola’s investment in Wallbox, a smart electric car charger; and Tepco’s investment in Zenobe Energy, an energy storage consultant.
Corporate activity in energy venture investing is taking place against the backdrop of rising energy VC activity in general. At USD 2 billion, more money went into early-stage venture capital deals for energy technology companies in the first half of 2019 than the first six months of any previous year, except 2018.
While the growth in energy VC activity in recent years has been driven by transport deals, non-transport deals have made up more than half of the deal value in 2019 so far. This may indicate a rebalancing between sectors after a flurry of recent activity around electric vehicles in particular, but it remains too early to say. Some of the major recipients of early-stage VC funding in 2019 include: Hozon Automobile and Enovate Motors, Chinese developers of performance electric cars; Commonwealth Fusion; a lower-cost nuclear fusion system designer; CalBio, producers of new biogas digesters; and Faraday Grid, an inventor of novel power grid transformers.
There are two trends behind these numbers that reveal a changing sector.
First, the growing deal value represents fewer, larger deals. The number of VC deals for energy start-ups is not rising. Yet, even excluding all outlier deals of more than USD 50 million, the average deal size in the first half of 2019 was higher than for any year since 2012.
Second, the geographical rebalancing of the energy VC market continues. As recently as 2013, 80% of the money went to energy start-ups in North America. Yet over the last three years, Chinese companies have represented over 50% of deal value as well as most very large deals, some of which have been as large as USD 1 billion.
In the first half of 2019, there have been fewer deals in China, but Europe is on track to claim its highest share of the market yet. If we exclude deals over USD 50 million, one-third of the 2019 deal value went to companies in Europe, also representing one third of the deals by number.
Overall, VC and corporate investment in energy technology start-ups have returned to growth, and the types of technologies they are supporting are broadly aligned with clean energy transition goals. Both types of investment serve energy innovation and bring private capital in support of pressing global challenges. The IEA will continue to monitor these trends as useful indicators of where companies and markets are placing bets on future technology value.
However, VC deals still remain a small element in the context of total R&D spending. We estimate total public research and development (R&D) spending by governments to be at least three times larger than the VC market, and private sector spending on R&D may be three or more times larger again. Furthermore, certain types of technologies are underserved by the type of capital that is mobilised by VC. These notably include capital-intensive hardware for renewables and large-scale low-carbon technologies, such as carbon capture. The risks for investors in technologies that have long lead times and uncertain markets are higher. As if to illustrate this point, Faraday Grid, a top fundraiser as recently as January 2019, entered administration in August. Boosting economic growth and transforming the energy sector through low-carbon innovation will require governments and the private sector to strengthen the interface between policy, research funding and VC investment.
Related commentaries have been published recently that explore other key factors shaping the value chain for energy investment and finance, including changing business strategies in the oil and gas and power sectors, and capital allocation choices between different energy sectors in energy transitions.
Vineyard Wind on Friday unveiled details of its offshore wind proposal centered on Bridgeport, an initiative that would create "thousands of jobs" and "help make offshore wind a statewide industry," the company said in an announcement.
The "Park City Wind" proposal comes as the New Bedford, Mass.-based company bids into Connecticut's request for proposals for offshore wind projects alongside Ørsted and Eversource and Mayflower Wind. The state said it is preparing to make a decision next month.
“Our commitment to Connecticut is significant,” Vineyard Wind CEO Lars Thaaning Pedersen said in a statement. “We see a future with thriving ports in both New London and Bridgeport and manufacturers in every corner of the state working to literally lift this industry off the ground in the U.S. If Park City Wind is selected, the jobs and economic opportunities created by this project will be available in the region for decades to come.”
Vineyard Wind, which owns leases in waters south of Martha's Vineyard and Nantucket, would plan to transform Barnum Landing, an underused part of Bridgeport Harbor, into a manufacturing and staging facility, Pedersen said in a call with reporters. After the construction phase, Vineyard Wind would turn it into "a long-term hub" for at least 25 years for workers servicing the offshore wind operation.
Vineyard Wind, a joint venture of Copenhagen Infrastructure Partners and Avangrid Renewables, submitted five different projects in response to Connecticut's request for proposals, from 400 megawatts to up to 1,200 megawatts, the equivalent of powering 600,000 homes annually, Pedersen said.
"... Park City Wind could generate upwards of $1.6 billion in direct economic benefits and create as many as 12,000 direct, indirect, and induced full-time equivalent (FTE) job years across Connecticut," the release stated.
Among other partnerships, Vineyard Wind's proposal calls for partnering with Mystic Aquarium and the University of Connecticut on researching the impact of noise and other marine construction activities on North Atlantic right whales and other marine species, Pedersen said. Commercial fisheries also will be studied, according to the release.
“The investment that Vineyard Wind is making in better understanding how to maximize the environmental benefits of this technology in design, installation and operation is extraordinarily important," Stephen M. Coan, president and CEO of Mystic Aquarium, said in a statement. "Vineyard Wind understands that the question is not whether ocean wind technology is beneficial; it is how to make it more beneficial for the whole ecosystem.”
Over the last 18 months, offshore wind has been rapidly growing in the United States, with states from Virginia to Massachusetts, announcing procurements, Pedersen said.
In Connecticut, the state Department of Energy and Environmental Protection is seeking proposals "from providers of energy derived from offshore wind facilities that are Class I renewable energy sources" for as much as 2,000 megawatts in total, states the request for proposals issued in August. DEEP has received proposals from three bidders, according to Kristina Rozek, department director of communications.
The bids were due Sept. 30. Rozek said the agency is working diligently to be able to make selection decisions in November.
Vineyard Wind, Ørsted and Eversource, and Mayflower Wind, a joint venture of Shell New Energies and EDPR Renewables North America, submitted the bids. Mayflower's bids included 800 megawatt and 400 megawatt proposals, The Day reported.
Ports in high demand
Ørsted and Eversource, which held a groundbreaking this week for its new office on Bank Street in New London, have submitted proposals as part of its Constitution Wind project, 65 miles from the New London shoreline.
"Following up on the selection of our Revolution Wind project by the state and our investment to turn New London State Pier into a world-class offshore wind center, our proposed Constitution Wind project will be delivered by the industry’s leading experts to ensure the project is achievable, sustainable and successful for Connecticut,” Ørsted North America President and Ørsted U.S. Offshore Wind CEO Thomas Brostrøm said in the announcement at the end of last month.
Vineyard Wind is "watching with great interest" as Ørsted and Eversource negotiate with the Connecticut Port Authority on the plan to upgrade State Pier into a hub to accommodate the offshore wind industry.
With states looking into offshore wind energy "up and down the Eastern seaboard," Vineyard's CEO said that his company sees the need for several ports to be developed for staging and construction — and even more facilities for the manufacturing, operation and maintenance — of wind farm components. Pedersen said there are "very few ports that don't sit behind bridges or other obstruction, and Connecticut is very fortunate that it actually has two such ports": New London and Bridgeport.
"We would need to work with all the ports that are being made available," he said, and his company would make an effort in a public-private partnership to develop new assets. If New London were available, he said his company could see it being used for this project and potentially others.
"We expected to be a significant player in this industry and both New London and Bridgeport are interesting to us," he said. "We know there is another tenant in New London and we're following that with great interest but in the big picture, we need to develop more of these port facilities ..." He said the company thinks Bridgeport is an "excellent starting point."
The Connecticut Port Authority has been under scrutiny in recent months. Senate Republican Leader Len Fasano, R-North Haven, announced in a news release Friday that he requested a second public hearing on the Connecticut Port Authority, in light of a "whistleblower's" comments to the news media.
Last month, state Sen. Cathy Osten, D-Sprague, and Rep. Christine Conley, D-Groton, also called for another hearing.
k.drelich@theday.com
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large area in which energy is utilised is in heating, which about 50% of global energy production is used for heating. In the UK central heating accounts for approximately 80% of national heat demand, which for 37% CO2 emissions in the UK in 2016. In order to meet the Paris Agreement target the UK should reduce CO2 emissions by 80% by the year 2050 in comparison to CO2 emission levels of 1990. To address this need, a movement towards the de-carbonisation of heating and cooling systems using renewable energies is taking place. In this regard, solar energy is used to generate both heat and electrical power on both large and small scales.
Solar panels are used to convert solar energy into heat and electricity. Most solar panels are designed to convert solar energy to only one of these forms, and an electrical photovoltaic (PV) panel is typically no more than 20% efficient. The rest of the absorbed sunlight rays are converted into heat. The temperature rise due to this heat reduces the performance of PVs. Hence, the energy that is not converted into electricity by the PV panels must be extracted to prevent reduction of PV efficiencies. PV panels can be actively cooled by passing a fluid through the rear of the panel. It then becomes possible to extract both heat and electrical power. This combined solar heat and electrical power system is known as a Photovoltaic/Thermal (PVT) system. The challenge here is that the heat energy recovered from the hot PV panel is does not have high temperature to cover the heating demand of a household.
One solution to this challenge is to integrate the PV panel with a heat pump. An area of research with this technology is in Indirect Expansion PVT Heat Pump (IEPVT/HP) systems. In order to test the validity of the system an experimental rig of the IEPVT/HP system has been designed and built in an indoor monitored environment in which certain parameters of the system can be controlled. In the experimental testing of the system, these parameters are controlled and varied; the solar irradiation received by the cooled solar PV panel (produced by a solar simulator); the mass flow rate through the cooling of the PV panel; the volume of the water tank supplying the cooling water to the PV panel and feeding the heated water to the heat pump. The integrated system utilises a closed water loop to cool the PV panel and transport the heat to the water-to-water heat pump. As the water is not used as the working fluid by the heat pump and only as transport media for heat, the system is called an Indirect Expansion Photovoltaic Thermal Heat Pump (IEPVT/HP) system.
Experimental results show that cooling the PVT panel using the developed integrated system, reduces significantly the panel temperature from 102oC to 50oC (for solar irradiation of 650 W/m2), demonstrating the promising function of the system in cooling the solar photovoltaic panels. Such an effective cooling of the panel, increases the on-site electrical efficiency of the PV panel by 25% compared to the un-cooled PV panel. The coefficient of performance (COP) of the heat pump found to be as high as 3.5, confirming the high performance of the developed hybrid system.
Total renewables across the Electric Reliability Council of Texas footprint jumped by more than 34% in third-quarter 2019 compared to the same timeframe a year ago, marking the largest year-on-year growth across the nation, which helped drive US renewable generation up 0.3%, according to data from grid operators and S&P Global Platts Analytics.
ERCOT total renewable generation averaged 213,003 GWh/d for Q3, third behind California ISO at 252,474 MWh/d and SPP at 245,470 GWh/d. ERCOT solar generation climbed 45% to average 15.3 GWh/d, wind generation jumped 33% and hydro generation increased 14% year on year, according to ERCOT data.
Current installed wind capacity for ERCOT is 22,244 MW, with an additional 4,521 MW under study for 2019, according to ERCOT spokeswoman Leslie Sopko. Current installed solar capacity is 1,878 MW, up 20 MW from the end of 2018, with 1,137 MW under study for 2019.
ERCOT set an all-time peakload record of 74,666 MW on August 12, and a weekend peakload record of 71,915 MW in August. The grid operator also set a new September peakload record of 68,546 MW on September 3, surpassing the previous September record set in 2016 by more than 1,500 MW.
Midcontinent Independent System Operator was second for biggest moves in total renewable generation for Q3 at a 17.5% increase year on year, according to grid operator data.
The increase in renewables helped drive down MISO prices, with on-peak real-time locational marginal prices across the ISO averaging about $28.41/MWh in Q3, down more than 21% year on year, according to ISO data.
Other regions that showed total renewable generation increases in Q3 were NYISO and the Southwest Power Pool, which were both up roughly 7.2% year on year, and Cal-ISO, which added 6.9%, according to grid operator data. All other regions fell year on year, led by ISO New England, which decreased 41.3%.
In NYISO, the growth was led by other renewables, which increased about 2% year on year, while SPP renewable growth was led by wind, which grew 38%, and hydro, which increased 19%, according to grid operator data.
SPP added a 100-MW project in the last quarter and expects to see another 800 MW registered by the end of the year, according to spokeswoman Meaghan Sever.
The grid operator set two wind peak generation records in September when wind generation reached 16,972 MW on September 11 and then surpassed that with 17,109 MW on September 30, Sever said. SPP also set an all-time peakload record of 50,662 MW on September 19. More recently, SPP set a renewable penetration record of 73.67% at 2:14 am October 9.
The growth in renewable generation helped drive down SPP's North and South hubs on-peak real-time locational marginal prices, which averaged $27.64/MWh in Q3, down 2% year on year, according to SPP data.
Cal-ISO maintained its position as the grid with the largest renewable output share across the US, with wind, solar and other renewables up at least 20% year on year.
China’s production and sales of new energy vehicles (NEVs) in September continued their year on year decline, showed data from the China Association of Automobile Manufacturers (CAAM) released on Monday October 14.
NEV production and sales in China stood at 89,000 units and 80,000 units in September respectively, down 29.9% and 34.2% from September 2018. The decline in sales expanded from a 15.8% drop in August.
For the first nine months of 2019, NEV sales amounted to 872,000 units, up 20.8% from the same period last year, with production rising 20.9% on an annual basis to 888,000 units.
CAAM data also showed that car sales contracted on a yearly basis for the 15th consecutive month in September, falling 5.2% from a year ago to 2.27 million units. This rebounded from August’s 1.96 million units due to a traditional high demand season of September and October.
Sales of automobiles in January-September were 10.3% lower than the same period of 2018. The decline narrowed from a drop of 11% in January-August.
Hot Chili has nailed a 596m long copper-gold drill intersection at its emerging Cuerpo 3 deposit as the Perth-based company ramps up exploration at the Cortadera copper-gold discovery in central Chile, returning a trifecta of stunning and consistent results over the last few months.
The ASX-listed junior said this week that its latest hole, had returned an intersection of 596 metres at 0.5% copper and 0.2g/t gold starting from a depth of 328m down-hole.
Importantly, the drill intercept also contains a higher-grade zone comprising 184m at 0.7% copper and 0.3 g/t gold from 430m.
This early exploratory drilling has confirmed that a newly uncovered, bulk tonnage, higher-grade zone extends from the northern to the southern flank of Cortadera’s main copper-gold porphyry zone at Cuerpo 3.
The new hit is over 300m from the original discovery diamond hole that returned 188m at 0.9% copper and 0.4g/t gold from 516m in late June.
The entire southern flank of the porphyry is now open and therefore, higher-grade copper-gold mineralisation could extend right across Cortadera’s main porphyry zone, management said.
Located southeast of Hot Chili’s open-pit Productora copper-gold-molybdenum deposit, Cortadera has now returned several highly encouraging drill results following the company’s bid to acquire a 100% interest in the privately-held venture earlier this year.
A third deep vertical diamond drill hole is now complete at Cuerpo 3 and a fourth hole is currently underway.
The third hole recorded broad intersections of mineralised porphyry from 50m to 330m down-hole and a stronger zone from 494m to 622m down-hole.
Assay results are still pending for this hole.
Hot Chili is fully funded to complete up to 13 additional deep holes as part of the phase two work program and upon completion of this work, an initial mineral resource estimate should be established for Cortadera.
The company recently completed a $12.1 million capital raising to help it develop what it says is one of the South American country’s most significant copper-gold porphyry finds of the past decade.
The phase two drill program will also include shallow RC holes associated with near-surface high-grade chalcocite zones intersected in drilling across Cortadera’s three other outcropping porphyry centres.
With a potentially mammoth resource shaping up now at Cortadera just 14km from the already impressive Productora deposit, Hot Chili looks like it is onto a significant, tier-1, bulk tonnage, copper-gold deposit that just might become irresistible in time to any majors that might happen to be sniffing around.
One thing seems certain, however, most of them would now have Hot Chili on their watch lists.
Is your ASX listed company doing something interesting ? Contact : matt.birney@wanews.com.au
From April 1, 2018 to June 30, Silvercorp continued its extensive exploration programs and completed 21,272 metres of underground diamond drilling and 3,274m of exploration tunneling at the LMW mine
Exploration drilling is ongoing at the LMW mine and all other mines at the Ying Mining District in Henan Province
( ) (NSYEAMERICAN:SVM) on Tuesday released results of its exploration programs at the LMW mine in China.
Exploration drilling is ongoing at the LMW mine and all other mines at the Ying Mining District in Henan Province, the company said in a statement.
From April 1, 2018 to June 30, Silvercorp said it continued its extensive exploration programs and completed 21,272 metres of underground diamond drilling and 3,274m of exploration tunneling at the LMW mine.
Results of underground drilling continuously extended the major mineralized vein structures along strike and downdip, and exploration tunneling exposed high-grade mineralization zones within major production vein structures, the company said.
Highlights of selected drill hole intersections:
Hole ZKX11111 intersected a 1.34m interval from 135.86m to 137.20m, 0.97m true width, of vein LM17W1 grading 1,211 grams per ton (“g/t”) silver (“Ag”), 11.58% lead (“Pb”), and 0.92% zinc (“Zn”) at the 634m elevation.
Hole ZKX1302 intersected a 1.22m interval from 121.20m to 122.42m, 1.21m true width, of a new vein grading 661 g/t Ag, 14.00% Pb, and 0.28% Zn at the 708m elevation.
Hole ZKX0513 intersected a 1.66m interval from 185.43m to 187.09m, 1.36m true width, of vein LM17W grading 859 g/t Ag, 4.53% Pb, and 0.31% Zn at the 661m elevation.
Vancouver-based Silvercorp said the underground drilling program is being conducted with three underground rigs from the current production levels to delineate the downdip and along-strike extensions of known mineralized vein structures in the production area and test for new veins in the previously less-explored areas.
Contact the author: [email protected]
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The graphite cores of two ageing nuclear reactors at Hunterston in North Ayrshire have begun to crumble as cracks spread, prompting safety inspectors to impose tough new conditions threatening future operations.
Technical reports released by the UK government’s Office for Nuclear Regulation (ONR) reveal that at least 58 fragments and pieces of debris have broken off the graphite bricks that make up the reactor cores.
According to ONR there is “significant uncertainty” about the risks of debris blocking channels for cooling the reactor and causing fuel cladding to melt. This could cause an accident and a leak of radioactivity.
HONG KONG (Reuters) - Hong Kong leader Carrie Lam scrapped a meeting with U.S. Senator Ted Cruz, the highest profile U.S. politician to visit the city since anti-government protests broke out more than four months ago, the senator said on Saturday.
U.S. Senator Ted Cruz attends to reporters at the U.S. Consul General's House in Hong Kong, China October 12, 2019. Cruz said he wore black to show support with pro-democracy protesters in Hong Kong. REUTERS/John Ruwitch
Lam’s office had requested that the afternoon meeting be completely confidential and that Cruz refrain from speaking with the media about it, Cruz told journalists in Hong Kong.
“She seems to misunderstand how free speech operates, and also how freedom of the press operates,” said Cruz, a Republican senator from Texas and a vocal critic of China who was stopping in Hong Kong for two days as part of a regional tour.
“Ms. Lam’s cancelling the meeting is not a sign of strength. It’s a sign of weakness. It’s a sign of fear of the protesters in the streets of Hong Kong.”
Responding to a request for details about the scheduled meeting, Lam’s office said in an email: “The Chief Executive did not meet with the said U.S. Senator.”
For months Hong Kong has been paralyzed by unprecedented protests calling for democracy and against police brutality. The former British colony was returned to China in 1997 and promised broad autonomy for 50 years under a “one country, two systems” model. But many in Hong Kong accuse Beijing of eroding its freedoms.
On Saturday, demonstrators took to the streets again, and the government said petrol bombs were thrown inside a Hong Kong metro station.
“I stand with the people of Hong Kong calling on the government of China to honor the promises it made to the world when it promised to maintain political freedom in Hong Kong,” said Cruz, who wore black to show support for the black-clad protest movement.
Asked if he condemned violence that has flared during the protests, Cruz said he advocated non-violent protest with the protesters and democracy activists he had met.
BASKETBALL TWEET BACKLASH
Cruz said he believed Chinese President Xi Jinping was “terrified of millions of people in Hong Kong, but even more than that, millions of people in China yearning to live free”.
Those fears were “magnified on the world stage” by China’s response to a tweet by a U.S. basketball executive supporting Hong Kong’s protesters, he said.
China has accused the West of stirring up anti-Beijing sentiment in Hong Kong, and Chinese state media characterized the Houston Rockets general manager’s tweet as the latest example of meddling in China’s affairs.
“Had the Chinese government simply ignored the tweet, in all likelihood virtually nobody other than die-hard Rockets fans like me would have noticed the tweet,” he said.
“But President Xi’s fear and insecurity, combined with arrogance, a belief that economic blackmail could force the NBA (National Basketball Association) to be witting participants in global censorship, ended up ironically highlighting the message far more than it ever would have otherwise.”
There is “overwhelming bipartisan support” in the U.S. Congress for the people of Hong Kong, and Cruz said he was pressing for the Senate to take up and pass the Hong Kong Human Rights Act quickly.
FILE PHOTO: Hong Kong Chief Executive Carrie Lam speaks during a news conference in Hong Kong, China, October 8, 2019. REUTERS/Tyrone Siu
Asked if it was more important now than ever to pass the act, he said: “Absolutely, yes.”
The act includes measures like annual reviews of the Chinese territory’s special economic status and the imposition of sanctions on those who undermine its autonomy.
“We should continue to look for tools to stand up for human rights and for democracy and to speak clearly against repression and torture and murder,” he said.
Farmers lauded the Trump administration’s announcement Friday of a potentially dramatic increase in agricultural sales to China, but quickly warned they need to see a follow-through of actual purchases.
Treasury Secretary Steven Mnuchin said the agricultural purchases could scale up to $40 billion or $50 billion annually as part of a partial trade deal, potentially more than doubling the $24 billion in agricultural and related products China purchased from the United States in 2017.
Farmers, who relied on China as the top buyer for soybeans and sorghum and a key market for pork and dairy, have seen their incomes plummet during the 15-month conflict of tit-for-tat tariffs between the world’s two largest economies.
“I’m excited,” said Monte Peterson, a farmer in Valley City, N.D., of the first phase of a deal. “That’s a pretty good announcement for U.S. ag.”
But it will be important for China to actually take delivery of farm products and not just announce purchases. “We have to see it loaded and shipped out,” he said.
Iowa’s Republican senators also praised the progress, but noted that same caveat.
“Any time progress is made, that’s good news,” Iowa Sen. Chuck Grassley said in a statement. “Farmers in Iowa know far too well that the trade war has caused real financial pain in the heartland. But we need to know more about this deal, and follow-through from China will be key.”
“No new tariffs on goods plus additional purchases of agricultural products, like Iowa soybeans and pork, is a good sign,” said a statement from Iowa Sen. Joni Ernst. ”I look forward to learning more details about this phase of the deal.”
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At a news conference after talks with Chinese Vice Premier Liu He, President Donald Trump joked that the partial deal meant farmers “are going to have to work a lot of overtime.”
Neither he nor Mnuchin gave details on which products China had promised to buy.
China imposed an additional 25 percent retaliatory tariff on U.S. soybeans in July 2018, resulting in piles of unsold U.S. crops and dragging prices to multiyear lows.
Trump has pledged a $28 billion bailout package to compensate farmers, who widely voted for him in 2016.
“Our farmers are resilient, but they need a long-term resolution to this trade war where U.S. soy can be imported into China by all importers without any retaliatory tariffs,” said Jim Sutter, chief executive of the Soybean Export Council industry trade group.
China mainly has relied on Brazil and Argentina for soybean imports it uses to feed livestock for nearly a year and a half, but the preliminary deal could shift trade to the United States.
China ramped up purchases of U.S. pork ahead of the trade talks in Washington, with the U.S. government reporting record-large weekly export sales Thursday. Millions of Chinese pigs have died from a deadly disease in recent months, sending China on a global pork buying spree.
Economist Bill Lapp, president of Advanced Economic Solutions of Omaha, was skeptical of the $50 billion figure.
“We’ve seen these big-dollar figures before, and they don’t always come to fruition,” he said.
U.S. soybean prices climbed to the highest point since the start of the trade war ahead of the announcement Friday. Trump said it will take up to five weeks to get a written agreement.
“We are encouraged that both sides are at the negotiating table because it is important to reopen this market for American farmers,” commodity trader Cargill Inc. said in an emailed statement.
While Mnuchin told reporters Trump had agreed not to increase tariffs on $250 billion of Chinese goods to 30 percent from 25 percent, there was no mention of removing the tariffs Trump put in place more than a year ago.
Advocacy group Farmers for Free Trade said it was too soon to celebrate.
“The promise of additional ag purchases is welcome news but details on timeline, price, commodities and many other questions will have to be answered,” Brian Kuehl, co-executive director, said in a statement.
This photo taken in June 2016 shows Japanese Prime Minister Shinzo Abe feeding cows at a farm in Yamagata. (Kyodo)
TOKYO (Kyodo) -- Japan's Cabinet on Tuesday approved a bill to ratify a recently reached trade agreement with the United States, setting the stage for Diet debate during which Prime Minister Shinzo Abe is expected to face questioning over his claim that the accord is a "win-win" for both countries.
The government aims to secure parliamentary approval of the bill before the current 67-day extraordinary session ends on Dec. 9, in time for Jan. 1 when the United States wants the pact to come into force.
A key feature of the agreement is Japan's lowering or elimination of tariffs on U.S. farm products such as beef and pork.
It will enable U.S. farmers to enjoy the same treatment as their competitors in Australia, Canada and New Zealand, all members of what is now the 11-nation Trans-Pacific Partnership free trade pact following the U.S. withdrawal in 2017 under President Donald Trump.
When Japanese tariffs on $7.2 billion worth of U.S. food and agricultural products are reduced or eliminated, consumers in Japan will gain access to cheaper beef, pork, cranberries, cheese and wines among other products. To soften the impact on domestic farmers, the government plans to draw up measures to help enhance their competitiveness before the year's end.
Abe has defended the agreement, signed earlier in the month, as protecting Japan's national interests, especially as rice, the country's staple, is exempted from any tariff cuts. "It will bring benefits to consumers, manufacturers, workers and all people," he told parliament last week.
Diet questioning is likely to focus on the potential impact of the deal on the Japanese economy and whether it is in line with World Trade Organization rules.
But opposition party lawmakers are likely to probe particularly the exact nature of the two nations' agreement on U.S. tariffs on Japanese auto exports. Vehicles and auto parts make up about a third of Japan's exports to the United States.
"Which is the government's official Japanese translation? Is it that the elimination of tariffs will be negotiated further, or whether to eliminate tariffs will depend on further negotiations?" Yuichi Goto, a lower house lawmaker from the Democratic Party for the People, said at a parliamentary session on Friday.
Goto was taking issue with one of the pact's annexes in which the United States says, "Customs duties on automobiles and auto parts will be subject to further negotiations with respect to the elimination of customs duties."
Toshimitsu Motegi, Japan's top negotiator in the bilateral talks, said in response at Friday's session, "Based on the premise that the tariffs will be eliminated, we will negotiate when it will take place. That's the right way to read it."
Junichi Sugawara, a senior research officer at Mizuho Research Institute, called the wording, which some trade experts agree leaves room for interpretation, a "win-win" for both nations.
"The U.S. side can explain domestically that the elimination of auto tariffs has not been promised, while the Japanese side can say at issue is when, rather than whether they will be scrapped," he said.
In the TPP, the United States had promised to cut its 2.5 percent tariff on Japanese cars over 25 years and immediately scrap levies on about 80 percent of imported auto parts.
Motegi has said bilateral talks will continue on auto tariffs as the auto sector is undergoing a major transformation due to the emergence of electric and autonomous vehicles, which has changed the composition and importance of parts.
Failure to achieve the elimination of tariffs on cars and auto parts would remove the basis for the Japanese government's assertion that the United States will scrap levies on 92 percent of goods in terms of trade value.
Without auto trade, the figure would drop to below 60 percent. That, some opposition lawmakers say, would go against WTO rules that call for the elimination of duties on substantially all trade in a bilateral or multilateral agreement.
On the economic impact, the Japanese government is expected to give a more detailed estimate than its current forecast that the pact will give a boost of around 1.0 percent to the world's third-largest economy in terms of real gross domestic product.
The percentage was calculated by subtracting 1.5 percent, the estimated economic effect after the U.S. pullout from the TPP, from the 2.6 percent boost expected had the United States stayed in.
President Donald Trump’s claim that China is willing to address “agricultural structural issues” in a trade deal has the U.S. ag sector excited that real change may be coming to the U.S-China trading relationship beyond just increased commodity sales.
The U.S. biotech seed industry — as well as all the farmers that depend on genetically modified crops — and the U.S. poultry sector could potentially be two of the biggest beneficiaries.
China’s pledge to make massive new purchases of soybeans and pork are heartening to the U.S. ag sector, but more permanent changes to the country’s restrictive regulatory policies offer long-term fixes to problems that impede billions of dollars in U.S. exports.
Neither Trump nor U.S. Trade Representative Robert Lighthizer went into detail on what changes China has agreed to in the partial “phase 1” deal they said was agreed on last week. But one of those “structural issues,” alluded to by Lighthizer on Friday after two days of talks in Washington with Chinese Vice Premier Liu He, is reform of China’s opaque and lengthy biotech approval process.
USTR Robert Lighthizer
“We’re encouraged by the news of the partial deal that includes biotech,” said Andrew Conner, Senior Manager for International Affairs at the Biotechnology Innovation Organization. “China’s regulatory system is broken and the delays are costing U.S. farmers and the economy billions of dollars, so just fixing this issue would be a tremendous win.”
At the heart of the problem with China’s approval procedure is that the country continues to demand that new biotech traits go through the entire approval process elsewhere before Chinese officials even begin to study it. That delays for years when American farmers can start planting seeds with a new trait or export the crop.
The U.S. has been after China to change its “asynchronous” approval process for years and agree to begin studying traits at the same time as other countries around the world.
So, when Lighthizer said Friday that the negotiators “corrected biotechnology issues” and the deal would make it much easier for “American farmers to be able to ship to China, it prompted cheers from BIO, which tweeted: “We look forward to seeing the details of the agreement and working w/ the administration on implementation.”
Chinese approval is far more than just assuring access to China for U.S. corn and soybeans. It also means approval for planting in the U.S. because seed companies usually won't commercialize products at all without first getting the nod from Beijing. Once a trait is introduced in U.S. fields, it can end up inadvertently in supplies shipped to China, risking the potential for massive rejections of U.S. shipments.
“What this could mean, if it’s resolved, is farmers having access to new technology that can help increase their productivity, reduce their costs and bring billions of dollars to the U.S. economy,” Conner said. “But for that to happen, China needs to commit to systemic change and implement a predictable, timely, transparent and science-based biotech crop approval process.”
Jim Sumner, USAPEEC
American chicken producers are also hopeful that a deal with China includes both an end to China’s poultry ban and an agreement to accept a regional approach to banning the bird meat in the event of a disease outbreak.
China has kept a blanket ban on all U.S. poultry for years after an outbreak of avian influenza — long past any sign of the virus — and that means U.S. producers are losing hundreds of millions of dollars every year, says U.S. Poultry and Egg Export Council President Jim Sumner.
China is a relatively unique market that buys large amounts of chicken paws, a product that mostly goes into rendering in the American market.
“The opening of China — even if it was just for chicken paws alone … would increase the bottom line of U.S. chicken companies by $835 million per year,” Sumner told Agri-Pulse.
When the U.S. can sell some of the 1.5 billion pounds of chicken paws it produces to China, U.S. producers get about 87 cents per pound for what’s considered a normal protein dish in China. When the Chinese market is closed, U.S. producers get about 5 cents per pound for the paws from rendere
But U.S. producers want to sell more than just chicken paws to China, said Sumner. The country, which is dealing with a severe outbreak of African swine fever, is importing a lot more than just pork to make up for the lack of protein as it kills its pigs to try to halt the spread of the virus.
So far, countries like Brazil, Argentina and Thailand have cashed in the biggest on China’s increased demand for poultry. A new USAPEEC analysis shows China’s poultry imports in the first eight months of 2019 have risen by 48%.
“They are buying anything and everything they can find,” Sumner said. “We would certainly like to be a part of that.”
Details of the trade deal are still dependent on both countries working out the remaining issues.
Trump has said he would like the deal to be ready to sign when both he and Chinese President Xi Jinping are together in Chile next month to attend an Asia-Pacific Economic Cooperation summit.
“What I will tell you is we made substantial progress last week in the negotiations,” Treasury Secretary Steven Mnuchin said in a CNBC interview on Monday. “We have a fundamental agreement, it is subject to documentation, and there’s a lot of work to be done on that front.”
For more news, go to www.Agri-Pulse.com.
Bayer expects the number of claims in the United States related to Roundup herbicide to have surged in the third quarter, as the German drugs and pesticides maker tries to reach a settlement after earlier court rulings against it.
“With the substantial increase in plaintiff advertising this year, we expect to see a significant surge in the number of plaintiff filings over the third quarter,” the company said in a written statement.
Bayer, which acquired Roundup and other glyphosate-based weed killers as part of its $63 billion takeover of Monsanto last year, faces potentially heavy litigation costs as plaintiffs claim Roundup causes cancer, something Bayer disputes.
Bayer’s shares have lost about 30% of their value since last August when a California jury in the first such lawsuit found Monsanto should have warned of the alleged cancer risks.
The drugmaker said in July that the number of U.S. plaintiffs in the litigation had risen to 18,400 and it is due to provide an update on Oct. 30, along with quarterly earnings.
Analysts at JP Morgan, citing an analysis of Missouri court data, said in an Oct. 9 research note that the total number of glyphosate cases could rise to more than 45,000.
However, several lawsuits have been delayed recently as mediator Ken Feinberg tries to negotiate a settlement.
The increase “may reflect a campaign by plaintiffs’ lawyers and lead generators to increase the volume of plaintiffs as quickly as possible in connection with that process,” Bayer said, adding that the number of plaintiffs was not an indication of the merits of these cases.
Bayer has previously said that cases where lawyers expect to win the highest damages tend to be filed first.
The head of Bayer’s Crop Science unit, Liam Condon, already flagged a likely increase in the number of cases in a newspaper interview earlier this month, citing the prospect of a settlement and lawyers’ efforts to recruit new plaintiffs via media campaigns.
Bayer, which says regulators and extensive research have found glyphosate to be safe, has previously said it was banking on U.S. appeals courts to reverse or tone down three initial court rulings that have so far awarded tens of millions of dollars to each plaintiff.
USDA already makes revisions of the previous year’s soybean crop in the September stocks report. In fact, revisions are the norm. It has revised its estimate of the previous year’s soybean crop in 18 of the past 20 September stocks report.
Washington Insider: Growth Drug Use Under Pressure
In a development largely below the radar for most urban media, Food Safety News says this week that a mega Pork Producer JBS USA has banned the use of growth drug ractopamine in the hogs it purchases because it sees a growing trade opportunity with China “where the drug remains prohibited.”
Ractopamine is used by many producers to raise leaner pigs. However, that practice remains highly controversial and is banned in the EU and China who neither allow its use of or tolerate residues in imported meat.
JBS, owned by JBS SA based in Brazil, hopes to help China fill a huge gap created by the African swine disease by shipping it ractopamine-free pork. Other companies have similarly limited the drug’s use to allow competition in more export markets.
JBS, based in Greeley, Colo., limited its use of the growth drug on its own in 2018. The company now says it won’t buy hogs from any farm that uses it. FSN notes that China, the world’s leading pork producer and consumer, is being hammered by African swine fever—a disease that “is not harmful to humans but is always deadly to pigs.” And, by dropping use of the feed additive entirely, the company expects to accelerate competition for pork exports there.
There is no vaccine for African swine fever, which broke out in China a year ago. The World Organization of Animal Health reports it has since spread to more than 50 counties, which normally account for about 75 percent of the planet’s pork production.
FSN expects that the dramatic decline in the global supply of hogs will create enough demand to pay JBS to drop ractopamine to compete more broadly. JBS USA sells pork under brands including Swift and Swift Premium and until now has focused mainly on the domestic market, leaving China mainly to Smithfield Foods which is owned by China’s WH Group and bans ractopamine on company-owned and contract farms.
“We are confident this decision will provide long-term benefits to our producer partners and our industry by ensuring U.S. pork products are able to compete fairly in the international marketplace,” JBS USA said.
Tyson Fresh Meats, the beef and pork subsidiary of Tyson Foods, Inc. (NYSE: TSN), today announced plans to prohibit the use of ractopamine in the market hogs it buys from farmers beginning in February 2020.
Ractopamine is a feed ingredient that helps increase the amount of lean meat in hogs. While it is FDA-approved and considered safe for use, some countries such as China prohibit the import of pork from hogs that have been given the product.
Tyson Fresh Meats has been offering a limited amount of ractopamine-free pork to export customers by working with farmers who raise hogs without it, and by segregating the animals and products at processing plants. However, these programs no longer adequately meet growing global demand.
"We believe the move to prohibit ractopamine use will allow Tyson Fresh Meats and the farmers who supply us to compete more effectively for export opportunities in even more countries," stated Steve Stouffer, President, Tyson Fresh Meats.
Most of the hogs delivered to the company's pork plants are purchased from about 2,000 independent farmers.
The growth additive has frequently been in the news. It was approved by FDA in 1998 to improve the rate at which animals convert feed to lean meat and is used in other countries, including Canada and Brazil, for livestock production. However, China, Russia, the European Union and several other countries continue to question its safety and refuse to accept meat from animals that use the drug.
Since 2012, the standards-setting Codex Alimentarius Commission, the UN food standards-setting body, has established residue limits for the drug but animal rights and food safety groups have frequently petitioned FDA to lower the residue limits and have called for more study of the drug’s effects on human health and animal welfare.
However, trade disputes have continued in recent years and a number of politicians including Sens. Chuck Grassley, R-Iowa and Amy Klobuchar, D-Minn., have urged the U.S. to “demonstrate to Russia that its newfound commitment to WTO membership includes adherence to science-based standards, such as the CODEX MRL for ractopamine.”
And, the growth drug continues to be controversial both in export markets and among American activists groups such as the Center for Food Safety, the Center for Biological Diversity, and the Sierra Club who argue that the FDA has not done enough to test the potentially harmful effects of it on people, animals, and the environment.
So, we will see. The decisions by JBS and other US companies, as well as pressure from potential export markets certainly is upping the ante on the US industry, if not on the FDA. In addition, the meat industry is under increasing political and social pressure from many directions these days, and it would seem prudent to continue to undertake hard-nosed evaluations of product quality as fights for competitive position continue both domestically and abroad, Washington Insider believes.
Want to keep up with events in Washington and elsewhere throughout the day? See DTN Top Stories, our frequently updated summary of news developments of interest to producers. You can find DTN Top Stories in DTN Ag News, which is on the Main Menu on classic DTN products and on the News and Analysis Menu of DTN’s Professional and Producer products. DTN Top Stories is also on the home page and news home page of online.dtn.com. Subscribers of MyDTN.com should check out the US Ag Policy, US Farm Bill and DTN Ag News sections on their News Homepage.
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BHP Group Ltd, the world’s biggest miner, said on Thursday it will make a final investment decision on its long-delayed $17 billion Jansen potash project in Canada around February 2021.
Investors have been awaiting a decision by BHP on whether to go ahead with project, which would be its most significant investment in years, and which it hopes will provide another pillar of long-term growth.
In its September production report, BHP said project planning and work to finalize a port solution was continuing and the $5 billion-plus Stage 1 will be presented to the board for an investment decision by February 2021.
BHP, which has already spent $2.7 billion on Jansen, said in May it expects excess supply capacity of the crop nutrient to be used up by the middle of the next decade, while the Jansen project would create a “high-margin, long-life” mine.
Potash is a potassium-rich salt mainly used in fertilizer to improve the quality and yield of agricultural production.
Elsewhere, BHP posted a slight dip in its September quarter iron ore production due to planned maintenance at a key port, but maintained its fiscal 2020 iron ore production forecast.
The result was in line with analyst forecasts and came as the miner carries out ongoing maintenance at Port Hedland, the world’s biggest iron ore port, which is used by three of the country’s top four iron ore miners.
“Lower volumes reflected significant planned maintenance at Port Hedland, including a major car dumper maintenance program,” BHP said in a statement.
Output for the three months ended Sept. 30, BHP’s first fiscal quarter, was 69 million tonnes, down 1% on a year ago and 3% on the June quarter. Annual output is expected at 273 million to 286 million tonnes.
Iron ore prices have come off five-year highs touched in July as Brazil’s Vale ramped up production that had been curtailed by a fatal dam disaster, and Australian shipments are expected to moderate into year-end.
“Overall, a solid result for BHP with all key segments broadly in line with our estimates,” RBC said in a report.
“BHP’s more diverse portfolio mitigates the potential impact of falling iron ore prices...We maintain our preference for BHP over its key Australian peer Rio.”
Quarterly copper output rose 5% on a year ago as production recovered from outages in Australia and Chile, while metallurgical coal production fell after planned maintenance shutdowns.
Chicago wheat futures rose for a second session on Thursday to hit a three-month high, with short-covering by funds and cold weather in the U.S. grain belt underpinning the market.
Soybeans edged higher for the first time in three sessions, although gains were checked as traders waited for more clarity on U.S.-China trade negotiations.
The most-active wheat contract on the Chicago Board Of Trade added 0.3% at $5.15 a bushel by 0253 GMT, after climbing to its highest since July 19 at $5.16-1/2 a bushel.
Soybeans were up 0.2% at $9.30 a bushel, having closed down 0.6% on Wednesday and corn gained 0.1% at $3.92-1/4 a bushel, having closed down 0.4% in the previous session.
“The wheat market is well supplied but there is some short-covering and threat to supplies from U.S. weather,” said Phin Ziebell, agribusiness economist at National Australia Bank.
“We are not yet sure, what is the extent of damage from the cold weather in the United States.”
There is additional support for wheat stemming from news that Egypt bought 405,000 tonnes of Russian, French and Ukrainian wheat, at higher prices than what it paid at its last international tender on Oct. 8.
Commodity funds were net sellers of CBOT soybean, corn and soymeal futures contracts on Wednesday and net buyers of wheat and soyoil futures, traders said.
Traders are looking for fresh Chinese demand for U.S. agricultural products.
U.S. President Donald Trump said last week that China had agreed to purchase $40 billion to $50 billion worth of U.S. agricultural goods in a first phase of an agreement to end a 15-month trade war.
But China would make the purchases only if Trump rolls back levies put in place since the trade war began, Bloomberg reported on Tuesday, citing people familiar with the matter.
The U.S. Department of Agriculture (USDA) late on Tuesday said the U.S. corn harvest was 22% complete and the soybean harvest was 26% complete.
The agency will collect additional information on harvested acreage of corn and soybeans in Minnesota and North Dakota following recent snowfall in both states, the government said in a statement on Wednesday.
Ukraine has increased its grain exports by around 39% to 15.44 million tonnes so far in the 2019/20 July-June season thanks to higher wheat shipments, Ukraine’s agriculture ministry said on Wednesday.
https://www.hellenicshippingnews.com/wheat-hits-3-month-high-on-short-covering-cold-u-s-weather/
Norway’s Yara (YAR.OL) said on Friday it was starting a share buy-back program after reporting quarterly earnings that were broadly in line with forecasts, and said the supply-demand balance for urea fertilizer looks set to tighten further.
The company, one of the world’s largest fertilizer-makers, said it saw an improving trend for its products in spite of cereal prices being below the 10-year average, with a tightening global grain balance and receding urea supply pressure.
“Fertilizer demand growth is likely to pick up as increased grain production is needed to keep pace with consumption growth, and global grain stocks are relatively low, particularly in China,” it added.
Yara’s second-quarter profit before interest, tax, depreciation and amortization (EBITDA) rose 49% to $630 million before non-recurring items and IFRS 16 accounting effects, while analysts in a Refinitiv poll on average had expected $623 million.
The company plans to buy back 0.8% of its shares by the end of 2019, including some of the shares held by the Norwegian government, for an overall amount of around 800 million Norwegian crowns ($87.10 million) at today’s share price.
Yara said it expects spot prices for natural gas, its main cost, to be $160 million lower than a year earlier in the fourth and, and $50 million lower in the first quarter of next year compared to a year earlier.
It added it expects to decide whether to go ahead with a previously announced initial public offering (IPO) of its industrial nitrogen business in early 2020.
Gazprom tallies gas production, infrastructure progress in eastern Russia
10/15/2019
MOSCOW - Gazprom is making preparations for the first pipeline supplies of Russian gas to China via the Power of Siberia gas pipeline. Efforts for filling up the pipeline with gas from the Chayandinskoye field in Yakutia are going according to schedule, with start-up and commissioning operations undergoing at the field’s core facilities. Drilling of 176 gas production wells is completed, as the work is progressing ahead of schedule. Production drilling is in full swing at the Irkutsk Region-based Kovyktinskoye field, which will start feeding gas into Power of Siberia in early 2023.
An important link in Power of Siberia’s gas supply chain will be the Amur Gas Processing Plant, one of the largest in the world. The core equipment of the GPP’s first two production trains is nearly assembled, with works underway on the third train.
Expansion is being carried out at the Sakhalin – Khabarovsk – Vladivostok gas pipeline section between Komsomolsk-on-Amur and Khabarovsk. Large-diameter pipes are being transported to the welding stations along the pipeline’s route for the purpose of welding double-jointed segments.
Gazprom is systematically developing the Yamal gas production center, which is major and strategically important on a national scale. The sixth and final booster compressor station is being prepared to be brought onstream along with new production wells at the Bovanenkovskoye field. Pre-development of the Kharasaveyskoye field continues.
The operations in Yamal are synchronized with the ongoing expansion of the northern gas transmission corridor. Compressor capacities are being built within the Bovanenkovo – Ukhta 2 gas pipeline. A new compressor workshop is being prepared to come onstream at the Ukhta – Torzhok 2 gas pipeline. The Bovanenkovo – Ukhta 3 and Ukhta – Torzhok 3 gas pipelines are at the design stage.
Welding is nearly over at the 880-kilometer-long linear part that is planned to go into operation this year as part of the project for expanding gas transmission capacities in the northwestern region between Gryazovets and the Slavyanskaya compressor station (CS). Start-up and commissioning is taking place at the CS, which is the starting point of the Nord Stream 2 gas pipeline.
The TurkStream gas pipeline is going to be brought into operation before the end of 2019. Construction of the receiving terminal on the Black Sea coast near the Kiyikoy settlement is nearing completion. The landfall section in Russia and the Russkaya CS are ready for operation.
Efforts are being made to build the LNG production, storage and shipment complex near the Portovaya compressor station.
The issue concerning the progress of the major investment projects will be submitted for review by the Company’s Board of Directors.
Related News ///
FROM THE ARCHIVE ///
Venus Metals and Rox Resources have had another win at their Youanmi gold JV in the Murchison region of WA, this week announcing significant gold, copper, zinc and lead anomalies from aircore drilling just north of Spectrum Metals’ revered Penny West gold discovery.
The shallow, first-pass air core drilling picked up four significant intersections of note that clearly require follow up, with gold results peaking in two separate, one metre intercepts grading 0.73g/t gold and 0.17g/t gold.
Another drill hole contained a 0.16g/t gold assay and also included a 24m wide zone from 32m down-hole that was strongly anomalous in copper peaking at 0.23% copper from 36m.
A deeper intersection nearby produced a metre grading 0.29% zinc and 0.15% lead from 83m down-hole.
Given that the drill program is only first pass aircore drilling and simply designed to test the rocks below the unmineralised cover, grade is not overly important here – what is more important is the discovery of anomalous levels of multiple mineralisation – all of which begs the question, where are they coming from?
The coincident gold and base metal anomalies are considered important, as the JV partners have already shown that elevated lead, zinc and copper characterise many of the high-grade gold intersections they have previously drilled at Currans Find North, about 2km to the northwest.
Spectrum Metals has also noted elevated lead results from the sulphide mineral, galena, associated with the well-heralded Penny North discovery, just 4km south of Rox and Venus’ new aircore drilling results.
The recent drilling was targeting two distinct magnetic trends that the partners had delineated within the joint ventured exploration licence.
Both geophysical trends appear to contain anomalous gold and base metals assays from the recent aircore program, management said.
Historical drilling in the region was limited by a transported soil cover, which rendered conventional surface exploration methods such as soil sampling ineffective, effectively meaning it has remained mostly unexplored for economic mineralisation, particularly at depth.
The historical Penny West open pit produced 85,000 ounces at a staggering grade of 21.8g/t gold back in 1991-92 and gives some idea of the latent gold prospectivity of the wider Youanmi district.
That deposit still has a remaining resource of at least 230,000 tonnes grading 4.8g/t gold for 36,000 ounces, which does not even include the recent Penny North discovery’s gold resource.
The aircore program was specifically designed to search for the gold and base metal pathfinder elements similar to Penny West and Currans Find North, with the campaign delivering in spades so far for Venus and Rox.
A program of follow-up aircore drilling is already in progress by the JV partners across high-priority targets and assay results from this work will be highly anticipated by the market.
Is your ASX listed company doing something interesting ? Contact : matt.birney@wanews.com.au
Market Vectors Junior Gold Miners ETF (the Fund) seeks to replicate as closely as possible, before fees and expenses, the price and yield performance of the Market Vectors Junior Gold Miners Index (the Index). The Index provides exposure to a global universe of publicly traded small- and medium-capitalization companies that generate at least 50% of their revenues from gold and/or silver mining, hold real property that has the potential to produce at least 50% of the Company's revenue from gold or silver mining when developed, or primarily invest in gold or silver. The Fund will normally invest at least 80% of its total assets in companies that are involved in the gold mining industry. The Index is the exclusive property of 4asset-management GmbH, which has contracted with Structured Solutions AG to maintain and calculate the Index. The Fund's investment advisor is Van Eck Associates Corporation.
Basic Details Issuer Van Eck Fund NameVanEck Vectors Junior Gold Miners ETF Tax ClassificationRegulated Investment Company SymbolNYSEARCA:GDXJ Inception Date11/10/2009 Fund ManagerHao-Hung Peter Liao, Guo Hua Jason Jin http://www.vaneck.com/ Web Phone-800-8261115 Fund Focus Asset ClassEquity BenchmarkMarket Vectors Junior Gold Miners Index CategorySector FocusBasic Materials Development LevelBlended Development RegionGlobal Fund Statistics Assets Under Management$4.18 billion Average Daily Volume$19.82 million Discount/Premium0.09% ETF Expenses Management Fee0.50% Other Expenses0.03% Total Expenses0.53% Fee Waiver0.00% Net Expenses0.53% Administrator, Advisor and Custodian AdministratorVan Eck Associates Corporation AdvisorVan Eck Associates Corporation CustodianThe Bank of New York Mellon Corporation DistributorVan Eck Securities Corporation Transfer AgentThe Bank of New York Mellon Corporation Trustee Lead Market Maker AMEX:GDXJ Rates by TradingView Receive GDXJ News and Ratings via Email Sign-up to receive the latest news and ratings for GDXJ and its competitors with MarketBeat's FREE daily newsletter.
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Barrick Gold Corp,, fell short of analysts’ estimates for third-quarter gold production on Thursday, as lower output at its North Mara mine in Tanzania offset gains from its Randgold buy and the Nevada Gold Mines joint venture.
Operations at the Canadian company’s North Mara mine were hit by tax and environmental disputes, and restrictions were lifted in September after Barrick addressed concerns about seepage at the project’s tailings storage facility.
North Mara was operated by Acacia Mining and Barrick took full control of the miner after a British court approved its US$1.2 billion takeover.
Related
Barrick gained from its Nevada Gold Mines joint venture with Newmont Goldcorp Corp. that the company estimated to have produced 535,000 ounces of gold in the third quarter.
The venture was set up after Barrick abandoned its US$18 billion hostile bid for Newmont and the miners then agreed to combine their assets in the U.S. state.
Also boosting production was improved output at the Loulo-Gounkoto mine in Mali, which Barrick acquired through the purchase of Africa-focused Rangold Resources.
The bid for Newmont and the purchase of Rangold marked Barrick’s efforts to boost shrinking reserves, and cash in on rising prices for the precious metal.
Gold prices have gained 16 per cent so far this year, as investors sought relief in safe-haven assets amid a prolonged U.S.-China trade war.
Barrick beat Street estimates for copper output, driven by higher production at the Lumwana mine in Zambia. The company is considering selling the asset as the country’s proposed new mining taxes would make it challenging to generate adequate returns.
Gold production totalled 1.31 million ounces, lower than the second quarter’s 1.35 million ounces, while copper output rose 14.4 per cent to 111 million pounds, the company said.
Analysts on average estimated gold production of 1.35 million ounces, and copper output of 105 million pounds, according to Refinitiv IBES data.
Barrick said third-quarter gold cost of sales per ounce is expected to be about 11-13 per cent higher than the second quarter, primarily due to higher depreciation resulting from purchase price adjustments at Nevada Gold Mines.
© Thomson Reuters 2019
Source: Xinhua| 2019-10-12 20:18:53|Editor: huaxia
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Photo taken on Oct. 12, 2019 shows the scene after a tornado formed during the course of Typhoon Hagibis hit Chiba Prefecture near Tokyo, Japan. (Xinhua/Deng Min)
A man in his 50s was found dead in an overturned car in Chiba Prefecture near Tokyo, possibly hit by a tornado formed during the course of Typhoon Hagibis, local government officials said, and according to information provided by rescuers and other authorities, at least 50 people were injured in the prefecture and elsewhere in the country.
TOKYO, Oct. 12 (Xinhua) -- Typhoon Hagibis made landfall on the Izu Peninsula on Japan's main island at 7:00 p.m. Saturday local time, bringing heavy downpours and winds, while the country's weather agency issued heavy rain emergency warnings for more prefectures.
A man in his 50s was found dead in an overturned car in Chiba Prefecture near Tokyo, possibly hit by a tornado formed during the course of Typhoon Hagibis, which also ravaged several houses, local government officials said.
According to information provided by rescuers and other authorities, at least 50 people were injured in the prefecture and elsewhere in the country.
Photo taken on Oct. 12, 2019 shows the scene after a tornado formed during the course of Typhoon Hagibis hit Chiba Prefecture near Tokyo, Japan. (Xinhua/Deng Min)
Japan remained at its highest alert level as the Japan Meteorological Agency (JMA) issued new special warnings of the severe rainfall for Ibaraki, Tochigi, Fukushima, Miyagi and Niigata prefectures at 7:50 p.m. Saturday local time.
The agency has already issued an emergency warning in the afternoon, saying heavy rainfall "with a level of intensity observed only once every few decades" is predicted in Tokyo and the six surrounding prefectures of Gunma, Saitama, Kanagawa, Yamanashi, Nagano and Shizuoka.
Typhoon Hagibis, meaning "swift" in the Philippine language Tagalog, could possibly bring rainfall amounts not seen since a deadly typhoon in 1958, the JMA said.
The agency has downgraded Typhoon Hagibis' intensity to "powerful" from "very powerful." As of 6:00 p.m. local time, it had an atmospheric pressure of 955 hectopascals at its center and was packing winds of up to 216 km per hour.
Rio Tinto is looking for copper and zinc-lead deposits in four Chinese regions, including Xinjiang and Inner Mongolia, as part of an exploration venture with state-owned China Minmetals Corp [CHMIN.UL], a spokeswoman for the Anglo-Australian Miner said on Friday.
The two companies set up a 50-50 joint venture (JV) to explore for what they called world-class mineral deposits in China in June 2018, but it was not previously clear which minerals they were looking for or which regions they were targeting.
Technical teams are carrying out field assessments in the major mineral belts of Xinjiang and Inner Mongolia, as well as in China’s southwestern Yunnan province and northeastern Heilongjiang, the Rio spokesperson said in an email.
“The JV is working with partners to secure targets for testing within these prospective belts.”
Mining projects backed by foreign investors are rare in China, although Ling Yueming, the country’s vice minister of natural resources, told the China Mining conference this week that steps were being taken to open up the state-dominated sector and level the playing field for all firms, whether Chinese or from overseas.
One mining industry source familiar with the copper exploration program said Rio was hoping the Southern Gobi copper-gold belt in Mongolia, which contains its massive Oyu Tolgoi mine, extended into Inner Mongolia in China.
Also speaking at China Mining, an annual gathering of mining executives, government officials and equipment manufacturers in the northern Chinese city of Tianjin, Rio’s exploration director for Australasia, John Kilroe, said on Thursday the company would welcome further exploration partnerships in China.
China’s copper imports rose 10.15% in September from a month earlier, to their highest in eight months, data from the customs showed on Monday, as higher prices in Shanghai drew shipments to the world’s top consumer of the metal.
Arrivals of unwrought copper, including anode, refined and semi-finished copper products into China, stood at 445,000 tonnes last month, the General Administration of Customs said.
That was up from 404,000 tonnes in August but down 14.6% from a bumper 521,000 tonnes in September last year, which was the highest monthly total since March 2016.
Over September, Shanghai copper prices edged up 0.7% and have averaged higher than London prices in other recent months, giving traders an opportunity to profit from the price difference by shipping metal into China.
“The comparison between Shanghai and London prices provided more favourable conditions for copper imports,” said Yang Changhua, copper analyst with research house Antaike, adding that demand for unwrought copper also increased as copper scrap supplies fell recently.
Copper stocks in bonded warehouses in China slumped to 295,500 tonnes by Sept. 30, the lowest since at least 2013, according to Refinitiv Eikon data, implying a tighter market as a crackdown on scrap imports boosted demand for other forms of copper.
Drawdowns in bonded stocks are reflected in China’s unwrought copper import numbers.
China’s factory activity shrank for a fifth month in September, pointing to persistent pressure on the world’s second-biggest economy and its copper-intensive manufacturing sector amid the bruising trade war with the United States.
Imports of copper concentrate, or partially processed ore, came in at 1.581 million tonnes, the customs data showed, down 12.9% from 1.815 million tonnes in August.
Also, China’s aluminium exports fell 6.7% in September from the previous month, underlining the impact of two key smelter outages in August.
The world’s top aluminium producer last month exported 435,000 tonnes of unwrought aluminium, including primary metal, alloy and semi-finished products.
That compared to exports of 466,000 tonnes in August and was down 14.2% from 507,000 tonnes in September 2018.
Minority shareholders in major zinc producer Nyrstar are seeking 1.48 billion euros ($1.63 billion) in damages from global commodities trader Trafigura over the restructuring of the Belgian firm, the shareholders’ lawyer said on Saturday.
Nyrstar was on the brink of bankruptcy before Trafigura stepped in. The Geneva-based trader has a 24.4% stake in the Belgium-listed firm.
The statement outlines for the first time the total damages sought by the minority shareholders and marks an escalation in the fight for Nyrstar after several months of legal action.
As part of the deal to save Nyrstar, lenders had to write off part of their debt or agree to extended repayment schemes while all the firm’s operating assets were transferred into a new subsidiary called Newco 2 based in the UK, in which Trafigura holds a 98% stake.
The remaining shareholders were then left with a 2% stake in the operating assets through a holding company called Nyrstar NV .
Nyrstar is one of the world’s largest zinc smelting companies with plants across Northern Europe, the United States and Australia. It also has zinc mines in North America.
The shareholders allege that Nyrstar’s board did not pursue profit by acting against its legal duties and committed fraud.
“On the basis ... of fraudulent avoidance of the law provisions regarding liquidation of companies, which require a decision of the general meeting of shareholders,” according to the statement.
As part of the lawsuit, the shareholders will seek to nullify the decisions of Nyrstar’s board that accepted the “lock-up agreement,” or restructuring terms, in April.
As an alternative to cancelling the deal, the shareholders are seeking 980 million euros ($1.08 billion) in compensation from Trafigura.
Nyrstar NV said on Friday it had received an unsolicited offer from Trafigura to buy the 2% stake for 22 million euros ($24.29 million).
Alongside the allegation of fraud, the shareholders allege that Geneva-based Trafigura abused its position as the single largest shareholder since 2015 and will seek 500 million euros ($552 million) in damages.
“On the basis of the abuse of the control (majority) by Trafigura ... resulting in severely unbalanced contracts and expensive overfinancing by which Trafigura gained pledges on Nyrstar assets,” the statement said.
Earlier this week, Belgium’s Financial Services and Markets Authority said it had opened a formal investigation into Nyrstar without providing details.
The shareholders will also seek damages for communication deficiencies.
In an Oct. 8 statement, Trafigura said its contracts with Nyrstar were market based and not the cause of Nyrstar’s financial troubles.
Chinese miner MMG Ltd is likely to have to halt production at its Las Bambas copper mine in Peru “within a week” due to protests that have blocked access to the site, a senior local executive told Reuters on Friday.
Alvaro Ossio, the mine’s vice president of finances, said Las Bambas, Peru’s largest copper minefield, had declared “partial” force majeure with contractors and was evaluating doing the same for copper sales.
“The plant is still operating with the stock we have, which is limited and will only give us a few more days of production,” Ossio said. If the blockade continued then “probably in less than a week it would clearly paralyze all production,” he added.
The potential freeze on operations comes amid wider protests that have hampered a number of mines in Peru’s southern copper belt. The country is the world’s second largest producer of the metal, which is also the main driver of its economy.
MMG said on Thursday that operations at Las Bambas would be affected by road disruption with supplies being blocked by anti-mining protests. The roadblocks have disrupted logistics at the site since Sept. 22.
The unrest has affected shipments from four mines that produce about half of Peru’s copper - Freeport-McMoRan Inc’s Cerro Verde, Las Bambas, Glencore PLC’s Antapaccay and Hudbay Mineral’s Constancia.
Las Bambas, which accounts for 16% of Peru’s entire copper output, had targeted between 385,000 tonnes and 405,000 tonnes of copper production this year, versus 385,000 tonnes in 2018.
Canadian miner Teck Resources Ltd (TECKb.TO) said bit.ly/2nMzPTw on Sunday that a union representing 473 workers at its Chile mine will start a strike on Oct. 14.
The strike at Teck Carmen de Andacollo Operations (CdA) in Chile from the Teck Carmen de Andacollo Workers Union will lead to operations at the mine being suspended.
The mine, located in central Chile about 350 kilometers north of Santiago, produced about 15,000 tonnes of copper in the quarter ended June 30.
Teck owns a 90% interest in the mine, according to its website bit.ly/2B5dvYj.
The company and the union could not arrive at an agreement at the end of a five-day mediation process, which concluded on Oct. 11, the Canadian miner said in a statement.
PT Vale Indonesia produced 50,531 tonnes of nickel matte between January and September, down 7% from the same period last year, the Indonesian mining company said in a statement on Monday.
Third-quarter output was up nearly 12% output from the second quarter, it said.
“Production in the third quarter was higher than production in second quarter as major maintenance activities have been completed,” CEO Nico Kanter said, adding the company was optimistic it could reach its full-year production target of around 71,000 tonnes of nickel matte.
Earlier this year Vale Indonesia lowered its 2019 output target to 70,000-72,000 tonnes from 74,000 tonnes.
Chile’s Codelco, the world’s largest copper producer, said on Monday that it is evaluating the closure of its Ventanas copper smelter in a polluted coastal region.
Media have reported that President Sebastian Pinera would announce the closure of the facility during the upcoming COP25 climate change conference, which will take place in capital Santiago in December.
Pinera has said he plans to use COP25 as a platform to urge countries to adopt more ambitious commitments to cut carbon emissions and other greenhouse gases that contribute to global warming.
The Ventanas smelter has been the target of criticism from social and environmental groups that accuse it of contributing to heavy pollution in the Quintero area on the central coast of the country.
“The old and low-scale Ventanas facilities are not very competitive and do not offer better prospects in the medium term, so the losses in recent years [of $50 million annually] are projected to continue,” the company said in its statement, adding that the facility’s refinery would continue to operate.
Codelco said a potential closure would require a legal modification and would need to be a planned process that seeks to minimize impact on workers and the surrounding communities.
Closing the smelter would require an investment of $150 million, Codelco said.
Environmental activists have long labeled the town of Quintero and its surroundings a “sacrifice zone” for the successive pollution episodes that have caused public health emergencies.
The coastal port city is also home to coal-burning power plants, some of which operate very near to residential areas
Chile’s Antofagasta Minerals , one of the world’s top copper producers, said on Tuesday it had reached a labor agreement with a union of supervisors at its flagship Los Pelambres mine in Chile.
The newly inked 36-month contract includes a 1% hike in salaries, a signing bonus of $17,000 as well as loan incentives for workers, Antofagasta said in a statement.
The 271-affiliate guild had previously threatened to strike after failing to reach agreement with the Chilean miner.
Antofagasta in July reported a nearly 22% jump in copper output in the second quarter, helped by an expansion at the sprawling Los Pelambres mine.
In 2018, Los Pelambres production totaled 370,500 tons.
China Hongqiao Group has agreed to set up a “green aluminium” industrial park in Southwest China’s Yunnan, according to a statement on Wednesday, as the top aluminium producer seeks to capitalize on the province’s hydropower resources.
Several Chinese aluminium companies, including Aluminium Corp of China, or Chinalco, and Henan Shenhuo, have been drawn to Yunnan, coveting access to cleaner hydropower for the energy-intensive smelting process.
Hongqiao Chairman Zhang Bo attended a signing ceremony with Yunnan government officials in provincial capital Kunming on Tuesday on jointly setting up the park, according to a statement from affiliate firm Shandong Weiqiao Pioneering.
In China, Hongqiao is often known as Weiqiao.
Hongqiao will take the lead on the park construction, developing an integrated hydropower and aluminum project, according to the statement, which did not specify a location or planned production capacity.
Last week, a website managed by the China Nonferrous Metals Industry Association said Hongqiao was planning to build a 2-million-tonnes per year integrated aluminium smelting and hydropower project in southeast Yunnan’s Wenshan prefecture, with construction due to start by the end of this year.
Yunnan vice governor Dong Hua, who also attended the signing ceremony, had told Reuters on the sidelines of the China International Lead and Zinc Conference in Kunming on Tuesday that Hongqiao was “in the process of discussing this issue.”
“Once they have discussed it, you will know,” he said, adding that he did not know specifics about capacity or location, which would be disclosed after the talks.
Hongqiao did not respond to a request for comment.
The company’s move underscores a geographical shift in China’s aluminium sector to more remote areas such as Yunnan from the heavily industrialized smelting heartland of Shandong in the east.
Hongqiao, which has an annual smelting capacity of almost 6.5 million tonnes of aluminium, all in Shandong, shut 2.68 million tonnes in 2017 amid a crackdown on unlicensed facilities.
It had previously floated the idea of moving the shuttered capacity to Indonesia, where it has an alumina refinery, but has not gone ahead with such a plan.
To expand in China, Hongqiao needs more capacity quotas. Metals consultancy CRU Group said it did not expect Hongqiao to change its total capacity and this project may be a relocation of existing capacity.
By Marco Aquino
LIMA, Oct 16 (Reuters) - The Peruvian government on Wednesday authorized the intervention of the armed forces and police to unblock access to one of the country's largest copper mines, after owner Chinese miner MMG Ltd said it may have to cease production at the site.
The decree, published in official newspaper El Peruano, declared a state of emergency for 30 days in an Andean area where residents have been blocking a road used by the mining company to transport concentrates for almost four weeks.
The measure involves suspending the right to free transit and to hold public meetings in various locations in the Andean province of Chumbivilcas in the region of Cusco, a key mining area in the Peru, the world's no. 2 copper producer.
The MMG-owned Las Bambas mine is close to having to halt production, a senior local executive told Reuters last week, adding the firm was evaluating declaring "force majeure" on sales because stocks were running out.
"The roads will be reopened because it is a mandate of the @PoliciaPeru. We are committed to dialogue, but that cannot be confused with weakness. We will fulfill our function," Interior Minister Carlos Moran said in a post on Twitter on Wednesday.
Las Bambas, which accounts for 16% of Peru's entire copper output, had targeted between 385,000 tonnes and 405,000 tonnes of copper production this year, versus 385,000 tonnes in 2018.
The unrest has affected shipments from four mines that produce about half of Peru's copper - Freeport-McMoRan Inc's Cerro Verde, Las Bambas, Glencore PLC's Antapaccay and Hudbay Mineral's Constancia.
Copper accounts for 60% of Peru's total exports, and is the main driver of the South American nation's economy. (Reporting by Marco Aquino; Writing by Adam Jourdan; Editing by Toby Chopra)
Our Standards: The Thomson Reuters Trust Principles.
China’s top copper smelters on Thursday raised their floor treatment and refining charges (TC/RCs) for the fourth quarter of 2019 by 20% from the previous quarter, according to three people with knowledge of the matter.
The China Smelters Purchase Team (CSPT) set the treatment charge floor at $66 per tonne, and the refining charge floor at 6.6 cents a pound at a meeting in Shanghai, said the people, who asked not to be identified due to the sensitivity of the matter.
That was up from $55 a tonne and 5.5 cents a pound in the third quarter, but still below the $90 a tonne and 9 cents a pound set for October-December 2018.
Copper miners pay TC/RCs to smelters to process their ore into refined metal. Higher charges indicate more abundant supply or that smelters have less need for concentrate.
The floor price agreed on Thursday also serves as an indication of the position that smelters in China, the world’s top copper consumer, will take in negotiations on a TC/RC benchmark for 2020, used for longer-term deals.
The hike in charges came a surprise, a source at a large mining firm said, given recent supply disruptions and a decline in spot TC/RCs over the course of this year.
“I don’t think they can buy a lot of tonnes of clean concentrate at that spot number,” the source said, adding that he saw no fundamentals-based rationale behind the move, especially given a supply disruption at the giant Las Bambas mine in Peru.
Smelter expansions in China, including Zijin Mining’s recent launch of a 150,000 tonnes per year plant in the northeastern city of Qiqihar, has also added to competition for concentrate.
Spot TC/RCs have fallen around 38% since the start of this year at $56.50 a tonne, squeezing the margins on smelters with heavy exposure to the concentrate spot market.
CSPT members are supposed to adhere to the floor charges in any spot processing deals.
To weather a dimming global growth outlook, the largest US aluminum producer plans to get leaner in the next 18 months, selling non-core assets after its worst streak of quarterly losses in at least three years.
Alcoa predicts world demand may contract by as much 0.6%, reversing a July outlook for growth of at least 1.25%. The forecast came a day after the International Monetary Fund cut to its 2019 global growth forecast this week, citing a broad deceleration across the largest economies.
Over the next 12 to 18 months, Alcoa intends to pursue non-core asset sales expected to generate an estimated $500-million to $1-billion in net proceeds. Despite the planned cutbacks, CEO Roy Harvey expressed optimism that the downturn in the market won’t last.
“When we think about 2020, we see demand springing back,” Harvey said in a telephone interview. “This isn’t a problem with the consumption of aluminum, this is a hiccup with what’s happening in the global economy.”
Alcoa shares climbed 5.4% in after-market trading at 5:25 p.m. in New York. The stock had lost 28% this year.
Metal producers have been caught in the crossfire as a trade war between the US and China hurt global growth, curbing demand for industrial raw materials. The average price for alumina, a key aluminum ingredient and one sold by Alcoa, dropped 44% in the third quarter from the same period a year earlier, according to S&P Global Platts.
The company also plans to realign its operating portfolio, and has placed under review 1.5-million metric tons of smelting capacity and 4 million metric tons of alumina refining capacity over the next five years. The review will consider opportunities for significant improvement, potential curtailments, closures or divestitures.
“It’s also simply a way that we can make sure we have the right cash to help weather through the different parts of the market cycle,” Harvey said after the earnings results were released. “That is for us an important component of making sure we have the cash to be able to move through our restructuring process.”
Alcoa said it’s implementing changes to make it leaner. The restructuring costs will be paid in cash in the fourth quarter 2019 with the remainder in the first quarter 2020, the company said. The new operating model is expected to generate annual savings of about $60-million in operating costs beginning in the second quarter of 2020.
The company reported a third-quarter loss of 44c a share, worse than analysts expected. Industrial metals have fallen as the US-China trade war weighs on global manufacturing and economic growth.
Goldman Sachs Group lowered its price forecasts on aluminum earlier this month, citing strong supply growth outside of China and the negative impact of economic uncertainty on capital spending. Harvey said the downturn may not last.
“When we think about 2020, we see demand springing back,” Harvey said. “This isn’t a problem with the consumption of aluminum, this is a hiccup with what’s happening in the global economy that we believe will come roaring back once this uncertainty is behind us.”
Canada’s main stock index dropped slightly by noon hour ET on Thursday, though cannabis stocks sprang ahead as legalization of marijuana derivatives including edibles and beverages took effect. Communication and discretionary stocks weighed the index down
The TSX Composite Index slid 17.98 points to at 16,409.20
The Canadian dollar recovered 0.40 cents to 76.15 cents U.S.
Shares of Cronos Group were the top performer on TSX with a jump of 58 cents, or 5.3%, to $11.61, while those of Aurora Cannabis climbed 24 cents, or 5.1%, to $4.98. Meanwhile, Canopy Growth surged 50 cents, or 1.9%, to $26.52, while Hexo Corp rose 41 cents, or 12.6%, to $3.66.
So-called Cannabis 2.0 comes a year after Canada legalized use of recreational marijuana. Sales are expected to begin in mid-December.
Another bright spot was shares of First Quantum Minerals, which jumped $1.34, or 13.4%, to $11.31, after Pangaea Investment Management, backed by one of China’s biggest copper producers Jiangxi Copper, raised its stake in the Canadian miner to 10.8%.
Enerplus fell 29 cents, or 3.4%, the most on the TSX, to $8.28. The second biggest decliner was Ag Growth International, down $1.94, or 4.8%, to $38.75
On matters macroeconomic, Statistics Canada reported manufacturing sales rose 0.8% to $57.6 billion in August, following two consecutive monthly declines.
The transportation equipment and fabricated metal industries were mainly responsible for the growth in August.
ON BAYSTREET
The TSX Venture Exchange pointed upward 2.05 points to 541.10
Seven of the 12 Toronto subgroups had plunged into the red by noon, with consumer discretionary and communications stocks each skidding 0.7%, while financials slid 0.6%.
The four gainers were led by health-care, ahead 2.6%, gold, up 2.4%, and materials, surging 1.8%.
Tech stocks were unchanged midday Thursday.
ON WALLSTREET
Stocks were fairly flat on Thursday, giving up most of their earlier gains, despite strong earnings results from companies such as Netflix and Morgan Stanley. Investors also digested news of European Union and the U.K. striking a deal on Brexit.
The Dow Jones Industrials sank 18.07 points to move into noon hour at 26,983.91
The S&P 500 came off its highs of the morning, but still led breakeven by 3.95 points to 2,993.64.
The NASDAQ Composite stayed afloat 11.83 points to 8,136.92
Netflix shares jumped 4% after the video streamer posted earnings that topped analyst expectations. The company reported a bigger-than-expected increase in international paid subscribers, which mitigated a big miss in domestic subscriber adds.
Morgan Stanley also got a boost from its quarterly numbers, trading more than 2% higher. The bank’s results got a boost from stronger-than-anticipated trading and advisory revenues.
Overall, the corporate earnings season is off to a solid start. More than 76% of the S&P 500 companies that have reported have topped analyst earnings expectations
Stocks also rose after U.K. Prime Minister Boris Johnson said "we have a great new Brexit deal" via Twitter. He called on British lawmakers to back the deal when it’s put before Parliament on Saturday. Meanwhile, European Commission President Jean-Claude Juncker tweeted that the deal was a "fair and balanced" one.
This is not a done deal, however. The U.K. Parliament has to approve the deal before it can be implemented.
Prices for the benchmark 10-year U.S. Treasury regained strength, lowering yields to 1.73% from Wednesday’s 1.75%. Treasury prices and yields move in opposite directions.
Oil prices lost 42 cents to $52.94 U.S. a barrel.
Gold prices gained $6.20 to $1,500.20 U.S. an ounce.
In 2017, the world’s largest copper producer - Chile’s Codelco - announced a plan to sell “green copper” at a premium price to customers using more sustainable practices like renewable energy and recycled water to cut its carbon footprint.
The project has run aground however, Codelco insiders and an executive said, as the miner realised it would struggle to guarantee its copper’s sustainability once it left the mine to be melted down and taken to market. Without that, traders said, higher prices were unjustifiable.
Now, the world’s largest miner of the prized red metal told Reuters it would drop the “green copper” plan piloted in one of its smaller mines in favour of a broader initiative to make its product more sustainable.
The move by the influential copper giant could, if successful, pave the way for more significant industry-wide sustainability standards for the historically high-polluting copper mining trade, analysts said.
But the failure with more ambitious “green copper” also represents something of a setback for Codelco, which is already struggling with ageing mines and lower copper prices due to the U.S.-China trade war.
Jorge Sanhueza, Codelco’s newly minted chief of climate change and traceable copper, told Reuters in an exclusive interview at the firm’s Santiago headquarters that it would instead seek to ensure that all its production, upwards of 1.7 million tons a year, could be tracked and measured for sustainability within two years.
“We have to get the deadlines approved by the board of directors but this is more ambitious than what we had before,” said Sanhueza.
Codelco’s latest bid to ride the sustainable wave comes just weeks before Chile is due to host the United Nations’ annual environmental summit, COP25, in December. Codelco did not disclose the estimated cost of the effort.
Heavy industry globally and the South American nation’s miners particularly are under pressure from governments and environmental groups to cut carbon emissions and make operations less resource-hungry.
Customers are also demanding products with a lower carbon footprint as scientific evidence mounts that emissions are driving climate change.
NOT WORRYING ABOUT PRICE - FOR NOW
A source linked to Codelco’s commercial strategy said that the original plan had been to sell the “green copper” at a higher price, but that initiative was shelved.
Copper traders told Reuters that Codelco had struggled to be able to certify its copper as traceable because once the ore left the mine, it still had to be driven to its markets, and transformed into cathodes in smelters largely powered by coal.
“Since there was no approved, industry-wide methodology (for sustainability) we were not willing to pay more for this copper,” one trader, who asked for anonymity so as not to affect his commercial relationship with the firm, said. “That is why Codelco had to continue selling its copper without attracting a premium.”
Sanhueza confirmed Codelco would set aside price differentiation for now.
“We’ve refocused to an extent to be able to make a reality the issue of traceability within the short term and from that point move towards a copper which is produced with a lower carbon footprint and social cost,” he said.
AHEAD OF THEIR TIME
Rachel Bartels, a senior managing director at consultancy firm Accenture, said Codelco was “ahead of their time” with its initiative at the one small mine but the company’s eagerness could still give it an advantage.
“You need a tipping point and we’re not quite there yet,” she told Reuters in London.
“They may not get a premium for it, but they may become the preferred supplier.”
To “trace” its copper, the company has set 75 parameters including water and clean energy use, gender equality and compliance with international labor regulations.
As there is at present no international benchmark for sustainable production of copper, it reviewed standards for other products such as aluminum and used guidelines from the industry-funded International Copper Association (ICA), Sanhueza said.
Codelco is building a $1 billion desalination plant to supply its operations in the north of the country, and assessing its energy contracts for ways to strip carbon emissions from them, albeit without a set deadline to migrate completely to clean energies, Sanhueza said.
“The good news is that one way or another, Codelco’s contracts are going to be decarbonized,” he said.
The state-owned miner faces another challenge to improve water recycling levels in its production processes. Although some of its mines in Chile’s north have rates of almost 90%, that drops to 54% and 62% in its key Andina and El Teniente mines.
As well as its internal targets, Codelco and other miners have been told by government to provide concrete plans to cut emissions before the spotlight of COP25 arrives.
In recent weeks there has been a flurry of announcements. BHP Group Ltd has said that the world’s largest copper mine, Escondida, will be run entirely on renewable energy while Anglo American Plc and French utility Engie have unveiled plans for hydrogen-powered lorries.
Juan Carlos Guajardo, head of Santiago consultancy Plusmining, said Codelco’s adventures in green copper highlighted that the industry was still grappling with sustainability best-practice.
“I still don’t see a standard in place,” he said.
Shares of First Quantum Minerals Ltd rose as much as 17% on Thursday after an investment firm backed by Chinese state-owned Jiangxi Copper Co Ltd increased its stake in the Canadian miner.
Pangaea Investment Management Ltd said it had purchased 6 million more shares in First Quantum, bringing its stake in the company to 74.64 million shares, or 10.8%.
The investment company has also entered into a forward contract through which it may choose to buy another 40 million shares.
Jiangxi Copper, one of China’s biggest copper producers, is a substantial shareholder in Pangaea.
First Quantum had confirmed in September that it was in talks with Jiangxi Copper for a potential sale of a minority interest in its Zambian copper assets after reports that the company had attracted takeover interest and has hired advisers to explore options.
First Quantum, however, said it had no knowledge of any potential takeover bids.
The company’s shares were last up 12% at C$11.18 after touching a session high of C$11.67.
China granted the fifth batch of import quotas of 57,365 mt for high-grade Category Six copper scrap, following import restrictions on such materials on July 1.
This was also the first issuance on copper scrap imports for the fourth quarter, with volumes standing only 24% of the counterpart for the third quarter, indicating China’s tighter control on waste imports.
According to the list released by the Solid Waste and Chemical Management Centre on October 17, the majority of the quotas went to companies in the key recycling hubs of Zhejiang, Guangdong, Anhui, and Tianjin. A total of 71 companies, such as Ningbo Jintian, Zhejiang Judong, and Tianjin Xinneng, were covered.
Based on a grade of 80%, the approved volumes in the latest release translate to 45,892 mt in copper content, SMM assessed.
The five batches of approval so far allowed a total of 541,582 mt of copper scrap to enter China, which equates to 433,266 mt in Cu content, according to SMM calculations.
Awarded volumes for copper scrap imports in the first four batches were in a downward trend, standing at 240,429 mt, 124,450 mt, 87,680 mt, and 31,658 mt, respectively.
Rio Tinto, one of the world’s top iron ore miners, signed its first spot trading contract denominated in Chinese Renminbi on Friday, in an effort to diversify procurement channels for Chinese customers.
The Anglo-Australian mining giant held a signing ceremony at Rizhao Port in China’s eastern province of Shandong, offering 10,000 tonnes of mid-grade iron ore SP10 to Shanxi Gaoyi Steel Co Ltd, said Zhang Qi, director of foreign ore at the Shanxi firm.
“We believe port sales could potentially help us to better serve our existing customers, as well as potentially opening up an opportunity to sell to new customers who do not participate in the seaborne market,” a Rio Tinto representative was quoted as saying.
Portside sales of Rio Tinto’s products at Chinese ports are currently sold via traders. Brazilian mining giant Vale SA launched yuan-denominated spot trading in 2016.
China imported 684.9 million tonnes of the steelmaking raw material in the first eight months of 2019. The weak Chinese currency is increasing the cost of seaborne iron ore.
The portside trading channel is only aiming to promote Rio Tinto’s niche products for now, the representative said.
China’s iron ore imports rose for a third straight month in September to a 20-month high, according to customs data released on Monday, fueled by firm demand at steel mills and stable shipments from big miners.
The world’s top iron ore consumer brought in 99.36 million tonnes of the mineral last month, the biggest purchase since January 2018, Reuters calculations showed. That was up 4.8% from 94.85 million tonnes in August and compared with 93.47 million tonnes a year earlier.
For the first nine months of the year, arrivals of the key steelmaking ingredient totaled 784 million tonnes, down 2.4% from 803.34 million tonnes in the same period a year ago.
Demand for iron ore at China’s steel mills has been firm despite some curbs last month when China implemented special measures to cut factory pollution ahead of celebrations for the 70th anniversary of the founding of the People’s Republic on Oct. 1.
Utilization rates at steel mills across China were around 68% in the first three weeks of September, but fell to 57.6% in the final week, the lowest on record since August 2012, data compiled by consultancy Mysteel showed.
“The curbs ahead of National Day were strict but were a one-off,” said Zhao Yu, analyst with Huatai Futures, speaking before data was released, noting that steel output has been running at high levels this year.
“Shipments from Brazil and Australia that were due to discharged in China last month were stable,” she added.
Stocks of iron ore at China’s major ports stood at 125.55 million tonnes as of end-September, little changed from end-August, data compiled by consultancy SteelHome showed.
China’s Ministry of Ecology and Environment said in September it would set stricter targets for polluting cities for this year’s autumn-winter heating season.
But analysts don’t expect a major impact on steel production.
“Steel mills have adapted to the pace and measures of output curbs over the past few years, so actual influence on production could be relatively small,” Zhao said.
China’s coal imports in September dropped 8.1% from a month earlier, as traders held up purchases amid an increase in domestic supply and slowing demand for the fuel from power generation companies.
Arrivals of coal, including thermal and coking coal, last month were 30.29 million tonnes, data released by the General Administration of Customs showed on Monday. Shipments stood at 32.95 million tonnes in August.
Guinea and Liberia signed a deal on Friday to allow several mines in Guinea, including the giant Nimba iron ore project, to export through Liberia, officials from the West African countries said.
The logistics of transporting tonnes of raw materials to port from mining sites in remote parts of Guinea has been a major hurdle for prospective developers of the country’s vast mineral wealth.
The agreement, which builds on an initial memorandum of understanding signed six years ago, is a victory for U.S.-Canadian investor Robert Friedland’s HPX, which last month acquired Nimba, a high-grade deposit in southeast Guinea.
“The mining projects in question are near the border with Liberia and cannot be profitable if they export through Guinea’s coast,” Guinea’s mines Minister Abdoulaye Magassouba told Reuters.
A graphite project owned by SRG Mining and a Zali Mining project would also be able to export through Liberia under the deal, Magassouba said.
The authorization to export via Liberia applies to the first 5 million tonnes produced at the mines, Magassouba said, beyond which the government will evaluate the feasibility of exporting via a 650-kilometre railway to the Guinean coast.
The “Transguineen” railway is to be built by the eventual owner of the much larger Simandou iron ore project, which the government insists must export through a Guinean port. Fortescue and SMB-Winning have bid to develop the mine.
Zogota, a nearby iron ore deposit owned by former Xstrata boss Mick Davis’ Niron Metals, has already negotiated an agreement to export through Liberia.
But Nimba and Zogota still need to reach agreements with Germany’s ArcelorMittal, the sole rail concession holder in Liberia, to allow them to use its infrastructure.
ArcelorMittal declined to provide an immediate comment.
Brazil’s Vale SA said on Monday its third-quarter iron ore production was up from the previous quarter but still down 17.4% from a year ago, as the miner slowly began to resume production at mines that were shut down following a deadly dam burst in January.
The company produced 86.704 million tonnes in the July-September period, up more-than two-thirds from the second quarter as operations resumed at Brucutu, its largest mine in the southeastern state of Minas Gerais, and at part of its Vargem Grande complex.
In a securities filing, the world’s top iron ore exporter added it expects to lift production capacity to around 50 million tonnes at its Vargem Grande complex by the end of 2021.
Vale shares were down 1.6% in morning trading in Sao Paulo.
The production figures were “largely in line with our expectations,” said BTG Pactual analyst Leonardo Correa.
“Thus, Vale’s path of recovery in iron ore volumes is progressing smoothly, and we expect these trends to continue into 2020-21,” he said in a research note.
Vale’s iron ore pellet production hit 11.133 million tonnes in the third-quarter, down 19.8% from a year ago, the mining company said.
Vale’s quarterly sales of the key raw material fell 11.8% from a year ago to 74.039 million tonnes.
The miner once again reaffirmed its previous full-year iron ore and pellets sales outlook forecast at between 307 million to 332 million tonnes.
The output and sales figures come a little over a week before Vale’s quarterly results.
Iron ore futures in China, the world’s top buyer of the steelmaking raw material, dropped to their lowest in more than two weeks on Tuesday after Brazilian miner Vale SA reported higher output in the third quarter.
Concerns about iron ore demand slowing in China, which makes about half of the world’s steel output, due to its renewed efforts to curb pollution by restricting steel mills operations in some areas also weighed on prices.
Dalian Commodity Exchange’s most-traded iron ore contract fell as much as 3.3% to 630 yuan ($89.12) a tonne, its weakest since Sept. 26. It was down 2% by 0312 GMT.
Vale, the world’s top iron ore exporter and China’s major source of high-grade material, on Monday reported a 35.4%quarter-on-quarter jump in output to 86.7 million tonnes in the July-September period.
The miner also said it expects to lift production capacity to around 50 million tonnes at its Vargem Grande complex by the end of 2021.
A deadly tailings dam burst at Vale’s Brumadinho complex in January prompted several dam and mine shutdowns for safety checks, tightening global supply and pushing iron ore prices to five-year peaks.
China’s spot 62% iron ore benchmark, which was steady at $92.50 a tonne on Monday, is still up 15% this year despite a 27% slump from its July 3 peak of $126.50 amid easing supply concerns, based on SteelHome consultancy data.
Improving iron ore supply from Brazil and Australia has pushed port inventory in China to a five-month high of 129.95 million tonnes, latest SteelHome estimates showed.
That improvement was reflected in China’s iron ore imports, which rose for a third straight month in September to a 20-month high, according to customs data released on Monday.
“For 2020, Vale expects to produce an additional 30 Mt (million tonnes) from the halted operations related to the Brumadinho tragedy, the miner said.
Other steelmaking raw materials also slumped, with Dalian coke slumping as much as 4.5% to 1,769 yuan a tonne, its lowest since Dec. 3, 2018.
The most-traded construction steel rebar on the Shanghai Futures Exchange fell as much as 2.3% to 3,325 yuan a tonne.
Hot-rolled steel coil, used in cars and home appliances, dipped as much as 2.2% to 3,301 yuan a tonne.
Stainless steel, made from nickel pig iron, slumped as much as 3.9% to 15,165 yuan a tonne, tracking Shanghai nickel’s sharp decline.
Global miner Rio Tinto said on Wednesday its third-quarter iron ore shipments rose 5%, helped by higher demand from Chinese steelmakers.
The global miner shipped 86.1 million tonnes of iron ore in the July-September quarter, compared with 81.9 million tonnes a year earlier.
Rio maintained its iron ore shipment forecast for the year of between 320 million and 330 million tonnes. Iron ore typically accounts for more than 60% of Rio’s earnings.
Global iron ore production has largely stabilized in recent months after a fatal dam collapse in Brazil squeezed supplies. Prices have also come off their highs touched earlier this year following the incident.
Rio cut its bauxite and alumina production forecast for the year, citing poor weather and facility maintenance.
China’s top steelmaking city of Tangshan, in Hebei province, issued a second-level smog alert on Tuesday due to expected pollution in the coming few days, local government-backed media reported.
The alert will take effect from 8 p.m. local time (1200 GMT) on Oct. 15.
Steel mills evaluated with “A-level” emissions performance, the cleanest level, will set independent emission measures. Mills rated “B-level” and “C-level” will need to halt sintering and pellet production, and “C-level” plants will also have to curtail blast furnaces operations by more than 50%.
Independent sintering operations, pellet and steel rolling firms were also ordered to halt work.
Other industrials plants in coke, casting, cement and glass were asked to reduce output during the alert.
The media report did not say when the alert would be lifted.
Benchmark Dalian iron ore futures slumped in morning trade on Wednesday, extending losses into a third session, after China’s top steelmaking city of Tangshan issued a second-level smog alert that requires mills to further limit operations.
The Dalian Commodity Exchange’s most-traded iron ore contract, with January 2020 expiry, fell as much as 1.7% to 627 yuan a tonne, its weakest since Sept. 26, and was down 1.6% by noon break.
The losses widened further after China outlined its annual anti-pollution plan for winter in a document released by the Ministry of Ecology and Environment.
China’s northern cities will be required to cut emissions of dangerous PM2.5 particles by an average of 4% this winter, according to a document issued by the Ministry of Ecology and Environment on Wednesday outlining its annual anti-pollution plan for winter.
FILE PHOTO: A man uses his mobile phone as he walks amid smog in Tianjin after the city issued a yellow alert for air pollution, China November 26, 2018. REUTERS/Stringer
The target for average concentration of PM2.5 - lung-damaging particulate matter smaller than 2.5 microns - applies to a group of 26 smog-prone cities in the north and the two municipalities of Beijing and Tianjin.
But the mandated reduction is lower than the 5.5% cut proposed in an earlier draft of the plan circulated on industry websites last month.
https://www.reuters.com/article/us-china-pollution/china-orders-northern-cities-to-cut-winter-pm2-5-levels-by-4-in-anti-smog-drive-idUSKBN1WV077
India’s coal imports are on track to decline for a third straight month in October, a drop that seems out of kilter with the ongoing struggles of state miner Coal India to boost domestic output.
India’s seaborne imports of both thermal and coking coal are on track to be around 13.3 million tonnes this month, according to vessel-tracking and port data compiled by Refinitiv.
This figure is likely to increase somewhat in coming days as more cargoes are confirmed from Indonesia to India, however, any departures now from South Africa and Australia, won’t arrive before month end.
Even if October imports do exceed the current estimate, it’s likely they will still fall short of the 15.3 million tonnes in September, which was down from 15.9 million in August.
The drop in coal imports looks surprising given Coal India’s recent woes, which include the flooding of a major mine and industrial action at some of its operations.
Coal India, the world’s largest miner of the polluting fuel, said it has lost 13 million tonnes, or 2.1%, of its annual output this financial year because of strikes at the eastern Talcher coalfields.
The Dipka mine in Chhattisgarh state, which produces about 30 million tonnes a year, was closed earlier this month after flooding when a nearby river burst its banks after heavy rain.
While Coal India has managed to restart some production, full output is likely to take longer than a month.
All this makes the company’s target of producing 660 million tonnes of coal in the fiscal year that started on April 1 seem unlikely, especially since output in the first six months of the fiscal year fell 6% from the same period a year ago.
While Coal India may be able to make up some of the lost output, it may be a challenge just to keep production at the same level.
Coal India’s troubles would seem to point to the likelihood of higher coal imports, but the vessel-tracking data isn’t showing this, or at least not yet.
COKING COAL DECLINE
One reason could be softness in India’s steel sector.
A close look at where India, the world’s second-biggest coal importer, is sourcing the material shows that the current weakness in imports appears to be concentrated in coking coal, used for steel-making.
Imports from Australia, which overwhelmingly ships coking coal to India, have been trending lower, with October arrivals slated to be around 2.2 million tonnes.
This is down from 3.2 million in September and 4.4 million in August.
If October arrivals from Australia are in line with the vessel-tracking data, it will be the weakest month since January.
The drop in coking coal imports is likely related to a softer steel sector, with top steel producer JSW Steel reporting an 8% drop in output to 3.84 million tonnes in the second quarter of the fiscal year, compared with the same quarter a year earlier.
Rival Tata Steel performed slightly better, increasing second quarter output to 4.5 million tonnes from 4.3 million a year earlier.
Weaker economic growth is likely crimping demand for Indian steel for manufacturing and construction, meaning the world’s second-biggest steel producer is unlikely to increase demand for coking coal.
THERMAL HOLDS UP
However, India’s thermal coal imports from top supplier Indonesia are showing signs of life, with 5.8 million tonnes scheduled so far to arrive in October, a figure likely to rise in coming days as more cargoes are arranged.
The final October figure is likely to be close to the 6.9 million tonnes of imports in September, which was up from 5.9 million in August.
Shipments from South Africa, another major supplier of India’s thermal coal, are also likely to rise, with October imports estimated at 2.9 million tonnes, up from September’s 2.4 million, although slightly down from August’s 3.2 million.
Overall, the picture that emerges is that India’s imports of coal imports are at risk of increasing in coming months to compensate for domestic output issues, while coking coal imports may struggle until the steel sector regains momentum.
China’s steel sector fragmentation is worsening, an industry official said on Tuesday, citing unplanned new capacity at small mills undermining government efforts to restructure and merge companies in the huge industry.
Beijing has been trying to consolidate the world’s largest steel market to curb excess capacity and pollution and has set a goal for its top 10 steelmakers to own 60% of production capacity by 2020.
However, Chinese Society for Metals (CSM) president Gan Yong said the trend is for less rather than more consolidation, saying unplanned capacity expansion at smaller mills was coming online while their big mostly state-owened rivals were struggling to do the same as quickly.
“There are some places using steel as a key contributor to economic growth as demand is robust,” Gan told Reuters on the sidelines of an industry event, adding some regions in China were not managing overcapacity controls very strictly.
The Ministry of Industry and Information Technology recently warned that the sector is still having trouble with increasing illegal capacity, including new mills not approved by the government and those that were supposed to be shut in capacity swaps.
Gan warned of growing competition in high-end products too. “There are signs of overcapacity in stainless steel, electrical steel and auto sheet steel,” he said.
In the first eight months of 2019, the world’s top steelmaker churned out 665 million tonnes of crude steel, up 9.1% on the year.
Production by members registered with the China Iron and Steel Association (CISA), mostly state-owned firms, grew at 5.9% year-on-year during that period. Production by non-members, mostly private firms, surged 19.4%, according to CISA.
China has eliminated 140 million tonnes of steel capacity at 700 small mills and 150 million tonnes of inefficient capacity at larger firms in the past four years as part of its environmental crackdown and supply-side reform.
China’s northern cities will be required to cut emissions of dangerous PM2.5 particles by an average of 4% this winter, according to a document issued by the Ministry of Ecology and Environment on Wednesday outlining its annual anti-pollution plan for winter.
The target for average concentration of PM2.5 - lung-damaging particulate matter smaller than 2.5 microns - applies to a group of 26 smog-prone cities in the north and the two municipalities of Beijing and Tianjin.
But the mandated reduction is lower than the 5.5% cut proposed in an earlier draft of the plan circulated on industry websites last month.
Flagging demand has returned to the forefront of concerns aired by steel industry executives gathered in the northeastern Mexican city of Monterrey for the annual general assembly of the World Steel Association, as the volume of steel China exports has seen steady declines, making it less of a target for criticism as it was in the past few years.
Among the end-use sectors that have come under scrutiny were automotive and construction, which have weakened this year, but may recover due to the largesse of governments seeking to stimulate demand.
AUTOMOTIVE DEMAND APPROACHING PEAK
Worldsteel expects automotive output to contract this year following shrinkages in demand in major markets such as Germany, China, Turkey and South Korea.
In the short term, this was attributed not just to market saturation and a pullback of purchasing incentives, but also to consumers postponing buying decisions as the auto industry transitions to hybrid and electric-powered options.
“On a longer-term basis, we’re probably approaching a long term peak for steel [demand] in the automotive markets,” said Edwin Basson, the association’s director general said. “I don’t think there will be substantial upticks in automotive demand.”
On the sharp declines in Chinese auto output and sales this year, Yu Yong, president of HBIS Group and incoming chairman of worldsteel, said: “The main reasons are perhaps not on the level of the economy, but more importantly due to the influx of new [energy] vehicles, ride sharing and consumer expectations on future demand.”
“I think this is a phase and will not have a lasting impact,” Yu said.
In China, the world’s biggest automotive market, vehicle output has slumped 13.8% on the year in January-August, but could recover in 2020 as the government is expected to introduce tax measures to boost passenger vehicle sales, especially for new energy vehicles, worldsteel said.
CONSTRUCTION PICTURE MIXED
In the construction sector, global growth is seen slowing to 1.5% this year and 1.2% in 2020 after a 2.8% rise in 2018, according to worldsteel.
Developed economies such as the US, Western and Central Europe, Japan and South Korea are expected either to shrink or show no growth this year and next. But in the developing economies of China, Southeast Asia and India, infrastructure investment has underpinned demand growth this year but could ease in 2020.
“In developed economies we do see some replacement activity; trying to make buildings more environmentally friendly, we also see some infrastructure replacement,” Basson said. “However in developing economies it is just growing on all fronts.”
On Turkey, Saeed Al Remeithi, CEO of Emirates Steel and chairman of worldsteel’s economics committee, said “we see a bit of rebound there and things are looking better, [as] the government is trying to reduce interest rates and boost consumption.”
Turkey, the top importer of ferrous scrap and an active exporter of rebar and billet after domestic demand slumped as a result of geopolitical events over the past year, is one of the countries Basson singled out alongside Southeast Asia where there should be continued strength in demand for construction steel arising from the shift in rural populations to urban centers.
Chinese steel exports, a punching bag conveniently blamed by industry executives elsewhere for worsening the global oversupply situation, have fallen 6% on the year in January-September to 50.3 million mt, and, annualized, mark the fourth straight year of falls from a peak of 112.4 million mt in 2015.
https://www.hellenicshippingnews.com/global-steel-demand-woes-exposed-by-drop-in-chinese-exports/
Australian mining giant BHP reported Thursday that its metallurgical coal and iron ore production fell in the first quarter of the 2019-2020 (July-June) fiscal year, but has maintained its guidance ranges for the 12-month period.
BHP's share of metallurgical coal production from its Queensland Coal business was 9.36 million mt over July-September, which is down 10% year on year and 21% lower than the April-June quarter. It is the weakest quarterly production the company has seen of the product since April-June 2017, according to data from the miner.
"At Queensland Coal, production was impacted by the planned major wash plant shutdowns at Goonyella, Peak Downs and Caval Ridge. This was partially offset by increased feed rates at the Peak Downs wash plant following a change in mine sequencing," BHP said.
In research notes Thursday, RBC Capital Markets said BHP's Q1 production was below their forecast of 11 million mt, while J.P. Morgan said it was slightly better than their expectation of 9.1 million mt.
Queensland Coal comprises the BHP Mitsubishi Alliance and BHP Mitsui Coal assets. BMA, Australia's largest supplier of seaborne metallurgical coal, is 50:50 owned by BHP and Mitsubishi Development. BMC is 80% owned by BHP and Mitsui has the remaining 20%.
Queensland Coal's total production -- including the other company's shares -- was 16.26 million mt in the September quarter, having fallen 10% year on year and 22% quarter on quarter, the results showed.
BHP is expecting its share of production in 2019-2020 to total 41 million-45 million mt, while the guidance for total production is 73 million-79 million mt.
BHP'S IRON ORE PRODUCTION SLIPS 1% YEAR ON YEAR
BHP's share of production from its Western Australia Iron Ore business in the September quarter was 61 million mt, which is down 1% year on year and 3% lower than the June quarter.
RBC said it had forecast 62 million mt for the period.
"At WAIO, lower volumes reflected significant planned maintenance at Port Hedland, including a major car dumper maintenance program, to further improve port reliability and provide a stable base for our tightly coupled supply chain," the company said.
"Major planned car dumper maintenance was completed on October 16, 2019, while the port maintenance program continues through the 2020 financial year," it added.
There are four main WAIO joint ventures, namely Mt Newman, Yandi, Mt Goldsworthy and Jimblebar. BHP's interest in each of the joint ventures is 85%, with Mitsui and ITOCHU owning the remaining 15%.
WAIO's production including all interests was 69 million mt, which is level year on year and down 3% from the June quarter, BHP said.
The total production was just below J.P. Morgan's 71 million mt forecast.
BHP is expecting its share of production at WAIO to be 242 million-253 million mt and the business' total production to be 273 million mt-286 million mt.
The outlook for China’s steel market softened in October amid expectations of a weak final quarter due to slower construction activity and robust steel production, the latest S&P Global Platts China Steel Sentiment Index, or CSSI, has found.
The October CSSI showed a headline reading of 16.04 points out of 100 in October, down from 26.18 in September. October’s reading was the lowest since June this year.
The headline CSSI, which monitors the outlook for steel orders over the coming month, has averaged just 23.45 over January-October, compared with 42.54 in the same period last year.
In the October CSSI, expectations for steel prices fell by 13.93 points from the previous month to 39.1.
A reading above 50 indicates expectations of an increase or an expansion and a reading below 50 indicates a decrease or a contraction. The CSSI is based on a survey of around 50 China-based traders and steel mills.
The outlook for crude steel production was flat last month, down just 0.56 to 44.44, though opinion differed about the potential impact of winter production cuts on output in the final quarter. China’s crude steel production is up by around 10% so far this year, according to government data.
More worrisome was the expectation that steel inventories would climb over the coming month, which could put downward pressure on steel prices. The CSSI sub-index for inventories rose by 15.09 points from September to 32.68 in October.
One mill source in Hebei province said stricter controls on production in northeastern China in October would be offset by stronger output from Shanxi province and mills in China’s south, which are not subject to the same controls.
“Therefore there won’t be a big drop in overall supply, and in any case demand will also be weaker as the weather gets colder,” the mill official said.
One mill manager said 90% of mills in Tangshan City in Hebei province would need to cut production and he believed the policy would be strict during the winter period. He was also worried about the level of lower priced steel imports coming into China. Russia and India have lifted their exports of flat steel and billet in recent weeks.
A source at another mill in Hebei province said the company’s environmental protection facilities were not as good as larger mills and therefore the mill would be ordered to cut production substantially over winter.
In general, mills that participated in the Platts CSSI were pessimistic about the market in Q4. They believed profits would be slimmer due to softer demand from the construction sector during the colder months.
Average profit margins for domestic hot-rolled coil and rebar were $24.30/mt and $47.90/mt, respectively, in September, Platts analysis showed.
