Saudi Oil Production Hits All Time High, Surges By 'Half A Bakken'
As hopeful US investors buy everything oil-related on the back of a lower than expected crude build this week (after the biggest build in 30 years the week before),
The Kingdom has stepped up overnight and ruined the dream of supply-restrained price recovery as it announced a surge in production output in March to yet another record high. The nation boosted crude output by 658,800 barrels a day in March to an average of 10.294 million a day, which as Bloomberg notes, is about half the daily production from the Bakken formation.
WTI Crude prices have slipped by around 2% from yesterday's NYMEX Close ramp highs as it appears Saudi Arabia is not willing to just let this effort to squeeze Shale stall.
Norwegian gas is likely to be price competitive enough to weather an influx of cheaper Russian gas expected into its European market this summer, a senior Statoil official said.
Europe's biggest gas producer does not expect to see Russia, the continent's biggest supplier, taking away its market share despite increasingly cheap oil-linked gas becoming available from the east, said Rune Bjornson, Statoil's senior vice-president for marketing and trading.
Supplies from Russian pipeline export monopoly Gazprom are estimated by analysts to rise to record levels this summer.
Russian long-term gas supply deals with European utilities are linked to oil prices with a lag of six-to-nine months, meaning that the collapse in oil prices will only start to fully feed into gas contracts this summer, making Russian gas cheaper.
Statoil sells much more of its gas priced against freely traded European gas hubs, raising expectations that Russian volumes could increase penetration into the market.
Bjornson said that spot prices on Europe's freely traded hubs will fall in response to any increase in Russian volumes, potentially lining up with oil-indexed levels and eroding Russia's competitive advantage.
"I don't necessarily think that is going to be the case because the Russian gas will also find its way into the market if there is a margin in there...simply because the oil-linkage takes it down below the (spot) market, the market is likely to follow suit in one way or another," Bjornson said.
"We expect flows to remain stable this summer," he said.
Caps on output from the Dutch Groningen gas field and gas exports from Western Europe to Ukraine left Western Europe's gas storage sites only a quarter full at the end of March, below last year levels, which is expected to keep demand high this summer.
Nor does Bjornson expect Statoil's share to be squeezed by a forecast rise in cheaper liquefied natural gas (LNG) shipments landing at northwest European terminals this summer, as demand in the world's top consuming market Asia slows.
"From a competitive point of view I think we are well placed," he said.
MGL: Gazprom oil linked contracts remain in the system? Most of the big utilities forced Gazprom to spot contracts on the basis of the now infamous exit clause, this article suggests that some remain. We've noted in the past that Gazprom pricing in Europe is all over the shop, with no rhyme or reason, so clearly there are some pure Oil index contracts remaining that are now gradually repricing down to the new Oil price level. It's just more pressure on gas pricing.
ICE Brent Crude Futures Achieves Open Interest Record
Intercontinental Exchange, the leading global network of exchanges and clearing houses, today announced that ICE Brent Crude futures achieved an open interest record of 2,006,759 contracts on April 15, 2015. The previous open interest record was set on April 2, 2015, with 1,992,780 contracts at ICE Futures Europe.
As of April 15, average daily volume for ICE Brent Crude Futures was 817,569 contracts year to date, up by 37% compared to the same period last year. Introduced in 1988, the Brent futures contract has continuously evolved to reflect changing market fundamentals and continues to meet the hedging requirements of market participants across the globe.
Schlumberger to cut 11,000 more jobs, earnings beat
Schlumberger Ltd said it would cut a further 11,000 jobs and reduced its capital spending plan for this year as the world's No.1 oilfield services provider prepares for an extended period of lower activity and pricing pressure, especially in North America.
The lower activity and pricing pressure led to a 9 percent drop in Schlumberger's first-quarter revenue, but "proactive cost management" helped the company's profit handily beat Wall Street's estimates.
Schlumberger shares were up 2.7 percent at 94.41 in extended trading.
The company said it expects a recovery in U.S. land drilling activity to be delayed and reiterated its March warning that the U.S. shale oil industry may have forever abandoned its heavy-spending ways in the face of sliding crude prices.
"We also anticipate that a recovery in activity will fall well short of reaching previous levels, hence extending the period of pricing weakness," Chief Executive Paal Kibsgaard said in a statement.
"The significant reductions in E&P spend are starting to impact supply in both North America and internationally, and supply is expected to tighten further in the second half of the year."
Schlumberger, which provides drilling technology and equipment to oil and gas companies, said it expects E&P spending to drop more than 30 percent in North America this year and by about 15 percent in international markets.
With the prospect of another plunge in crude prices looming, U.S. shale oil producers could face another round of spending cuts, which would further gut the oilfield services industry, Reuters reported in March.
Schlumberger said on Thursday that it now plans to cut 11,000 more jobs, bringing the total reductions announced this year to 20,000, or about 15 percent of its workforce.
The Houston-based company cut its capital expenditure plan for 2015 to about $2.5 billion from $3 billion.
Schlumberger said revenue fell nearly 9 percent to $10.25 billion in the first quarter ended March 31.
Revenue from its international business, which accounts for two-third of total revenue, fell 8 percent. Revenue from North America fell 12.5 percent.
Net income attributable to Schlumberger fell 38.8 percent to $975 million. The company's adjusted profit of $1.06 per share handily beat analysts' average estimate of 89 cents.
North America pretax operating margin fell to 12.9 percent, but beat UBS analyst Angie Sedita's estimate of 8 percent. International pretax operating margin rose to 24.1 percent from 22.8 percent.
MGL: These really small revenue falls are oddly impressive. The suspicion remains that this is simply evidence of the sheer inertia of the industry. With Oil prices down 50% did Big Oil really want to spend 9% lass than last year? Or were they locked into contracted capex which forced completion, and payments.
What we really need to know is how big is Schlumberger's backlog?
We can gain a clue from Shell's contractual obligations:
$420bn of purchase obligations in 2013. $402bn in 2014. Thats down 5%!
Shell says capex will be down some 15% this year, so those contractual obligations, by end year, should also contract 15%.
YPF sees cost of Vaca Muerta drilling falling 10 pct
The cost of drilling in Argentina's vast but barely tapped Vaca Muerta shale formation will fall at least 10 percent by the end of 2016, state energy company YPF said on Thursday, part of an efficiency effort aimed at attracting much-needed investment.
The cost drop is expected to start in August when Argentina starts using its own sand in fracking, the process by which shale oil is extracted, rather than more expensive imported sand, YPF's Chief Executive Officer Miguel Galuccio said.
This may help Latin America's No. 3 economy attract the investment it needs to erase an energy deficit that costs billions of dollars per year in already low cash reserves.
YPF has already cut the cost of drilling a vertical well in Vaca Muerta to $6.9 million from a previous $11 million, Galuccio told reporters gathered on the outskirts of Buenos Aires for a demonstration of how YPF is refining fracking sand.
By the end of 2016, Galuccio said Argentina will produce all sand it needs for shale drilling.
"We are continually looking for ways to reduce well drilling costs. The sand is one form, which in itself will allow us to save 10 percent," Galuccio told Reuters.
"And there are other things we are doing which lead us to think we are going to save not only 10 percent. Our target will be much more than 10 percent."
That would come to a relief to international investors who have so far shied away from Vaca Muerta due to high costs as well as heavy trade and currency controls.
Galuccio said it currently costs $13 million to $14 million to drill horizontal wells in Vaca Muerta, located in Patagonia.
YPF is building a plant near Vaca Muerta that is set to start refining raw yellowish sand mined from the southern province of Chubut into the fine gray sand used in fracking.
YPF says it has about 300 wells producing up to 45,000 barrels per day of oil and gas equivalent, a fraction of Vaca Muerta's potential.
Santos Nears Start of its $18.5 Billion Gas Export Development
Santos Ltd. expects its $18.5 billion liquefied natural gas project in Australia to start production in about five months, pushing the country closer to becoming the world’s largest supplier of the fuel.
The Gladstone LNG project should begin around the end of the third quarter, the Adelaide-based company said Friday as it posted a 10 percent drop in first-quarter sales. That narrows the forecast start date of the plant from the company’s previous expectation of the second half.
The gas exports to Asian markets will give a boost to Santos, which has been under pressure amid a slide in oil prices. Australia’s third-largest oil and gas producer has cut spending and jobs while flagging the possibility of asset sales as it copes with the oil market downturn.
BG Group Plc’s rival LNG project in the state of Queensland has already begun shipments to Asia, while Origin Energy Ltd. and ConocoPhillips are building a third export development that’s set to start this year.
The plants put Australia on course to surpass Qatar later this decade as the biggest LNG exporter.
Santos’s sales in the quarter fell to A$825 million ($643 million), from A$913 million a year earlier, as the average oil price it received tumbled 44 percent.
MGL: Santos capex is dropping like a stone. As capex completes, supply increases. Santos is a text book example of the phenomenon.
Volumes are now rising. Prices are falling, and net income is going down too.
The real problem is that we just not seeing demand growth for LNG anymore. There's some opportunistic Chinese and Indian buying, but the the core of Japan, Korea, and Taiwan are stagnant in demand terms.
Here's the IGU LNG buildout for the next 3 years:
This remarkable table was published in 2014, and willfully ignores the 285m mt of capacity in the FERC queue. It assumes only 1 LNG export plant in the US.
Right now we have 4 export plants in construction, with a fifth, the Cheniere expansion, to announce FID next week.
AMSTERDAM, April 14 (Reuters) - Cheniere aims to take a final investment decision on its planned Corpus Christi liquefied naturalgas (LNG) export project in the United States within the next 30 days, undeterred by weak oil and gas prices worldwide.
Ramzi Mroueh, vice-president of origination at Cheniere International, said Cheniere had agreed financing for Corpus Christi and sealed a $9.5 billion engineering, procurement and construction contract with engineering firm Bechtel.
"We expect to sell another 2 million tonnes (of LNG supply from the project) by the end of the year," he said.
Cheniere is already building the United States' first LNG export plant at Sabine Pass, Louisiana, which is due to come on stream towards the end of the year.
A final decision on an additional two production trains at Sabine Pass LNG export project in the United States this year, specifically trains five and six, Mroueh said.
The moves suggest that weak oil and gas prices are failing to dent the boom in U.S. LNG export projects, spurred by massive gas supply growth from shale drilling in recent years.
"There is still strong interest in the market for our product despite slowdown and low oil prices," he said.
"We will be the biggest LNG producer in the Atlantic ... with 40 million tonnes of annual production," once Sabine Pass and Corpus Christi are built, he added.
This will take US export capacity to 80m mt by the end of 2018.
We have a 50% expansion in global LNG capacity hitting markets between now and 2018. Is it any wonder Tokyo Bay LNG prices are $7?
There are still investors in this market who think LNG prices are above $10.
LNG looks worse than Iron ore, and Shell's bid for BG to gain 15% of a market that is in massive oversupply looks like pure folly.
Here's LaVorgna: "As we can see from the chart below, the plunge in energy production is occurring in lagged response to the aforementioned fall in oil prices. We have found that the year-over-year change in oil prices is most closely correlated with changes in energy production when the former series leads by five months. This means that if it turns out that oil prices bottomed last month, production should begin to stabilize around September. Of course, between now and then, energy production and capital spending (capex) will be extremely weak."
Hedging Helps Canadian Oil & Gas Companies in Low Price Climate
Canadian oil and gas companies that hedged their oil production before the global oil price crash will be very relieved they did so. This CanOils study of 45 TSX-listed companies' Q4 2014 results (see note 1) shows that many Canadian companies made large realized hedging gains as the oil price fell to around $50 by year-end 2014. This study agrees with a recent EIA article, written using Evaluate Energy data, showing the impact of hedging on U.S. companies during the same period.
Whilst hedging may have seemed over-cautious at the start of the year, with oil prices not having wavered from the $90-$100 mark for quite some time, hedging eventually proved to be a prudent strategy given the collapse of commodity prices by almost 50% towards the end of the year.
Hedging contracts (also known as derivative contracts) are a common risk management strategy for oil and gas producers. A producing company will agree with a buyer to sell future production at a certain price, thus potentially limiting revenues if prices climb, but simultaneously shielding the producer from excessive losses should commodity prices suddenly fall.
The chart below shows that the group of 45 TSX-listed companies, as a whole, experienced both sides of the hedging dynamic in 2014.
Whilst high prices were not realized by the 45 companies to their full potential in Q1 and Q2, hedging has clearly helped significantly lessen effects of the commodity price downturn in Canada towards the end of 2014. The graph is almost identical to that reported by the EIA for U.S. companies using Evaluate Energy data. The lines for pre- and post-hedging revenues are almost parallel in Q1 and Q2, begin to converge in Q3 and then switch over dramatically in Q4 as benchmark oil prices began to tumble.
MGL: Hedging by the Oil industry has done its job. It has bought the companies time to adjust to the new reality of $60 Oil. Capex runoff, and project completions lie ahead, and in Canada supply growth will continue for the forseeable future.
"Western Canadian oil production in 2015 will continue to grow at about 150,000 barrels per day from last year—about 65,000 barrels a day fewer than previously forecast—with a similar gain expected in 2016, the industry lobby said, a result of investment in oil-sands projects that will come online over the next couple of years."
Capex intentions in Canada have fallen some 45%, but we still have a large core of project underway, contracted, and committed to completion.
This is the January CAPP foroecast which incorporates a 33% drop in Capex and a 68000 bpd cut in output growth, primarily from SAGD/shale curtailments. All of that growth in output will head South and East as exports.
PA Feb Natgas Production Numbers Show Decrease from Jan
Kudos to the Pennsylvania Dept. of Environmental Protection. On April 1 they published the very first monthly production numbers for oil and gas production in the state–for the month of January.
At the time, the DEP said going forward new production numbers would be released 45 days after the end of a calendar month, and that February’s numbers would be released by April 14. Those numbers were released–just before midnight on the 14th! They kept their word and are to be commended for it. MDN has analyzed the numbers from February, comparing them to January. Unfortunately several drillers have failed to file their monthly reports on time–most notable among them is EQT.
Because EQT’s numbers are missing for February (one of the larger drillers in PA), it throws off any kind of meaningful analysis. However, we have enough of the picture from other major drillers who did file on time–drillers like Cabot Oil & Gas, Range Resources and Southwestern Energy–that we can tell you this:Production in PA from January to February went down by an appreciable amount.
Currently, without EQT’s numbers in the mix, February production decreased 17% from January levels. Once missing numbers are added, we expect production to have decreased somewhere around 8-10% overall.
Adds to the picture that Oil and Gas volumes have now been falling, and by appreciable amounts for some time.
Meanwhile the front page of the WSJ is suggesting that Oil and Gas production begins to fall in May.
There is now a huge difference between perception and reality on US oil and gas production.
EIA figures are based on RIGs. State data is based on production and royalty payments.
State data from Texas, North Dakota, and now Pennsylvania is showing sizeable declines. January data is showing some 700kbp of Oil. We have not calculated the gas impact, but it will be sizeable. Possibly 2bcf per day. Add in this data from the all important Marcellus and we have a picture that shows US oil and gas production crashing.
Despite this US oil and gas inventory has risen in the past few months. This is a big deal. It implies, at least that final demand is nowhere near the levels being implied by the big data agencies. Over the next few months the market will wake up to this impact.
The profitability of some U.S. shale wells at current prices will almost double as cost cutting and technology turns them into cash gushers despite oil’s crash.
A report by Citigroup Inc. highlights what companies such as EOG Resources Inc. have been saying for months: that belt-tightening across the industry and more strategic drilling in prolific areas would deliver ample profits even at $50 crude.
The improvement is driven by costs that are expected to fall by 20 to 30 percent and techniques that allow rigs to wring 30 percent more oil or natural gas from each well compared with a year ago, according to the Citigroup report on Wednesday. That might bring some surprises when shale producers begin reporting first-quarter financial results over the next two weeks.
While investors are braced for widespread losses, the numbers may not be as bad as some expect, said Richard Morse, the lead author of the study. “Shale producers were hit by low prices in 2014, but they’re hitting back,” he said in the report.
Among specific companies, the potential for improvement varies greatly. SM Energy Co., which specializes in Eagle Ford wells, is expected to see costs of $32.52 a barrel. Penn Virginia Corp., which also drills there, still has costs of $135.55 a barrel when debt is factored in. Antero Resources Corp., which drills in Appalachia, has costs of less than $18 a barrel because of the productivity of its wells, according to the report.
The U.S. Energy Information Administration’s most recent report about the per-well output from shale rigs showed continuing productivity gains. Across the seven major shale-producing regions, oil output from new wells is expected to rise 3 percent in May compared with April. In the Permian basin, the largest producing formation in the U.S., the gain was more than 10 percent, the EIA said.
Such improvements make wells more profitable as more oil or gas is sold from every drilling pad. A year ago, Eagle Ford rigs produced a little more than 500 barrels a day from each well. With prices over $100 a barrel, that represents about $50,000 in revenue per well.
Now, the output in the same formation is almost 750 barrels. With oil selling for $56.26, that’s $42,000 in revenue. Throw in a cost reductions and the profitability is comparable to a year ago. Further improvements to both costs and productivity per rig will create the doubling or tripling of profits in some regions, the Citi report says.
Profitability across the Eagle Ford formation, the most prolific shale area that spans South and East Texas, will surge 40 percent this year if productivity increases and cost cuts hold, according to the Citi report. For the richest areas in the basin, profits will go up more than 60 percent. Gains of 20 to 30 percent will take hold in North Dakota, West Texas and other areas.
MGL: A month ago we said nothing works below $50 in the US. We're going to have to revise that statement.
Approximately 10% of wells work below $50. Quite possibly 30% work below $60.
It is far too early in this new environment to figure out where the landscape settles out.
We have: ~An enormous fracklog that has disrupted the data. Production overstated by 1-2mbpd. Demand similarly overstated by the agencies like EIA/IEA. ~Inventory build ongoing despite a real fall in yoy US production. ~Plummeting rig count leading to repricing of capex, that in turn leads to a repricing of well economics. ~Surging productivity cutting costs approx $1 per month. In August we were looking at $70-$80 breakevens for US shale, its now likely we have significant capacity that's economic at $60-$70.
There are so many moving parts right now, it is extremely difficult to posit reasonable scenarios for even 3 months out from here.
For example: the 'fracklog' is a ticking bomb. Most leases in the US require a refiling to abandoned after 12 months of non production. There is apparently a way of filing for temporary abondonment, but it is simply not clear what exactly that means. It is plausible we discover that companies are forced to either complete or abandon leases, and the first quarter issue next year will be exactly this problem. So the fracklog may not only be price triggered, it may be time sensitive too.
It is still not clear what happens in the monster known as the Permian. Is it the Marcellus of Oil? Or simply a dud. The best companies on the Permian acreage are being very vague on detail as to prospective economics. Every week, we go through a CXO, PXD, LPI or other Permian producer presentation, and end up little the wiser.
Its a big mess.
Only certainty: Saudi production rising inexorably, and ARAMCO happy to supply barrels above $60 in quantity.
Market sentiment is bullish, and celebratory.
Short the oil patch.
I have no names really for you, it's simply a matter of time. Digging through all this state data is a massive pain.
Regulatory OK of a natural gas pipeline expansion in B.C. improves the likelihood that the Petronas-led Pacific NorthWest LNG project will be built, but a final investment decision still awaits other government approvals, the proponent said Thursday.
On Wednesday, the National Energy Board said it will recommend federal approval of the North Montney Mainline Project proposed by Calgary-based TransCanada Corp.
The $1.7-billion expansion of its Nova Gas Transmission Ltd. (NGTL) system will consist of two 42-inch pipeline sections totalling about 301 kilometres. It will allow transport of gas from northeastern B.C. and other parts of Western Canada through TransCanada’s proposed Prince Rupert Gas Transmission pipeline to provide gas to the liquefied natural gas export facility on Lelu Island, near Prince Rupert.
“This decision is a key component to fulfilling a core requisite that informs our final investment decision,” said Pacific NorthWest president Michael Culbert in a release. “With this decision in hand — and awaiting other regulatory approvals — Petronas and our partners will continue to work cautiously toward a FID on the Pacific NorthWest LNG project.”
TransCanada said in a release construction cannot proceed until after the Pacific NorthWest LNG project has been sanctioned and it is proceeding with the Prince Rupert pipeline project, which has all required approvals.
MGL: Surely the BC based LNG projects have missed their sell by date?
~they are close to Tokyo, much closer than any other project. ~Alberta shale gas is abundant and cheap, so even at
But with LNG in Tokyo at $7 we simply cannot imagine these projects delivering better than $2 netback, at most, in Alberta.
The LNG port conversions south of the border are much cheaper, by a country mile, and those still look economic. Thats simply a function that conversion is much cheaper than de novo, and that most of the pipelines are already build or in place.
Though Gujarat and Rajasthan are at the forefront of solar power development in the country, other states are also making rapid progress in harnessing energy from sun.
Presently, Gujarat and Rajasthan account for over 50 per cent of India’s grid-connected solar energy capacity additions. However, states such as Madhya Pradesh and Maharashtra are also catching up fast, supported by their solar programmes.
As of February this year, total installed capacity of solar power was 3,383 MW, constituting 10 per cent of total installed renewable power capacity in the country.
Gujarat contributed 949 MW and Rajasthan’s installed capacity was 902 MW. Madhya Pradesh has added 500 MW, while Maharashtra’s commissioned solar power capacity was 334 MW. Other states, that have added more than 100 MW in solar, include Andhra Pradesh (237 MW), Punjab (120) and Tamil Nadu (112 MW).
The country has achieved more than its targets in grid solar and off-grid solar under the Phase-1 (2010-2013) of Solar Mission. Against the target of 1100 MW of grid solar power, 1686 MW of projects (including large plants, rooftops and distribution grid plants) were commissioned.
The Indian government has set an ambitious target of adding 100,000 MW by 2022.
The plan would include large scale deployment of rooftop projects under both net metering and feed in metering to achieve 40,000 MW of capacity till 2022.
Secondly, the Government would lay emphasis on grid connected projects to achieve 40,000 MW by 2022. For this, Solar parks have been set up in Gujarat and Rajasthan, and others have been planned in over 15 states.
Thirdly, the Centre would focus on large scale projects (100 MW minimum.) to generate the remaining 20,000 MW capacity.
MGL: Indian solar on target! It's unusual for anything in India to be on target. The plan is to grow Indian solar 100x in 7 years. No where else in our coverage do we have anything like this demand growth.
China Southern Rare Earth Group was officially launched on Thursday in Jiangxi province as part of the country's efforts to push industry integration.
The corporation based in Ganzhou City has registered capital of 100 million yuan (16.3 million U.S. dollars) with joint investment by three local companies.
Ganzhou Rare Earth Group Co., Ltd., Jiangxi Copper Corporation, and Jiangxi Rare Earth and Rare Metals Tungsten Group Corporation hold 60-percent, 35-percent and 5-percent stakes in the new group, respectively.
The three shareholders will complete injecting their related assets to the new corporation by the end of this year. The new group will continue to integrate other local rare earth firms.
To restructure and consolidate its rare earth market, China integrated big firms with dozens of small miners in late 2014 and established six major rare earth groups.
MGL: Ganzhou Rare Earth Group is now the only owner of rare earth mining rights, controlling all of the 43 rare earth mining rights licenses in Ganzhou. The group plans to continue to merge rare earth smelting separation producers, as it aims to become a fully integrated large-scale heavy rare earth group.
Seems to be privately run and maybe entirely owned by the CEO Bin Gong.
China Sends Nuclear-Industry Message With New Reactor Approval
A file picture taken on December 8, 2013 shows the joint Sino-French Taishan Nuclear Power Station outside Taishan City in Guandong province. Agence France-Presse/Getty Images
When China approved construction of the country’s first homegrown nuclear reactor, it was also sending a message to foreign companies whose Chinese projects are plagued by delays and cost overruns.
The State Council, China’s top government body, approved construction of its first indigenous nuclear reactor at a meeting on Wednesday. In doing so, it opened the door to intensified competition over who will provide the technology for the world’sbiggest nuclear growth market.
The reactor, called the Hualong-1, has been jointly developed by two state-owned companies. In essence, China National Nuclear Corp. and China General Nuclear Power Group are taking aim at reactors designed by U.S. nuclear giant Westinghouse Electric Co. and French rival Areva . Both have faced problems and delays in rolling out new reactors.
As part of a 2007 deal, Westinghouse agreed to help a Chinese technology company, State Nuclear Power Technology Corp., develop its own version of Westinghouse’s most-advanced commercially available reactor, called the AP1000. Under that deal, Westinghouse would work with China to build pilot AP1000 reactors before a local version was built by Chinese companies across the country.
But the first Westinghouse AP1000 unit is running far behind schedule, as component quality problems and other issues delayed construction. Chinese leaders have griped openly about the U.S. reactor’s delays.
MGL: China nuclear program starts delivering the goods. The invidious Westinghouse/Areva comparison may tell us more about health and safety issues in the Nuclear paranoid OECD than anything useful about the technologies.
Here's China's current Nuclear program:
Of course, this Nuclear program directly impacts coal's share of the Chinese electric market.
Ian Harebottle, who’s made his career from mining colored gemstones, has an emerald the size of a pineapple locked away in a safe. He’s not sold the unique bright-green rock because it’s so rare nobody really knows what it’s worth.
Welcome to the topsy-turvy world of colored gems, where abundance can mean higher prices and scarcity makes spectacular stones untradable. It’s a very different business from diamonds, the world’s most popular precious stone, traded in a liquid global market that makes pricing relatively transparent.
For colored stones, prices often increase with supply as jewelers acquire enough stock to justify marketing the gems to customers. Take regular emeralds: their value has appreciated 1,000 percent in five years as Harebottle’s Gemfields Plc and peers expanded mines, while marketing campaigns fronted by Hollywood star Mila Kunis gave demand a boost.
Now Harebottle wants to bring the same game to rubies. Gemfields’ Montepuez in Mozambique, estimated to contain as much as 40 percent of the world’s known supply of the deep-red stones, could triple output from the 8 million carats targeted for this year, according to the executive.
The potential rewards are compelling. At its first Singapore auction last December, Gemfields sold high-quality rubies for an average $689 a carat, dwarfing the $66 a carat for comparable emeralds. Production growth is underpinned by rising demand in China, where the color red symbolizes prosperity, health and wealth, making rubies an auspicious investment.
“With rubies there is a fairly healthy uplift potential,” said Harebottle, who has been chief executive officer of London-based Gemfields since 2009 and presided over an 11-fold jump in its shares in the period. “Over the next couple of years we should be able to double” prices.
His company, which has amassed 20 percent of the emerald market to become the biggest producer, plans to replicate that share in rubies. The December auction generated revenue of $43.3 million after Gemfields’ rubies fetched the highest price at any of its sales. That boost for the fragmented industry, still largely supplied by individual miners from Colombia to Burma, shows the impact of increasing output.
“We expect Gemfields to repeat with rubies the success it achieved by imposing order on emerald prices,” Investec Plc said. “The Montepuez ruby mine will rank among the best discoveries in Africa in decades.”
China's production of base metals mostly rose in 1Q
Production of refined copper rose 9.7 percent from a year ago in March as smelters expanded capacity amid an increase in supply of raw material.
The bureau last month said January-February production was 1.2 million tonnes, but did not give monthly breakdowns. In the first quarter, output increased 14.3 percent year-on-year to 1.85 million tonnes.
March output was likely higher than February when the Lunar New Year holidays slowed operations at smelters, said Yang Changhua, senior analyst at state-backed research firm Antaike.
"March output was higher mainly because of expanded capacity. We expect output to rise in April from March," Yang said.
Industry sources have estimated at least 300,000 tonnes of annual capacity would start production this year.
Meanwhile, production of primary aluminium reached a record 2.56 million tonnes in March, up from the previous high of 2.18 million tonnes hit in December 2014. Output rose 8 percent year-on-year.
In the first quarter, aluminium production climbed 7.5 percent on-year to 7.51 million tonnes.
China Merchants Futures has estimated China will add 4.3 million tonnes of annual aluminium capacity this year, with the bulk in the first and fourth quarters.
Production of refined nickel climbed 18.4 percent on-year to 28,320 tonnes in March. Output in the first quarter surged 27 percent from the year before to 81,870 tonnes.
Some nickel producers face output cuts in the near term due to low prices and weak domestic demand.
Refined tin output fell 10.6 percent from the year before to 13,250 tonnes in March due to weak prices. In the first quarter, production dropped 2.9 percent on-year to 39,297 tonnes, despite strong imports of tin ores and concentrates.
Chinese tin prices SN-1-CCNMM dropped nearly 5 percent in March. The price stood at 113,000 yuan ($18,240) on Friday, the weakest since mid-2009.
Tin output may slow in April after a large producer started some maintenance in mid-April that will last a month, traders said.
Multi-year lows in prices PB-1-CCNMM also weighed on refined lead production, pushing it down 7.9 percent on-year to 340,202 tonnes in March. Output dropped 6.6 percent to 987,868 tonnes in the first quarter.
Refined zinc production climbed 10.4 percent on-year to 491,042 tonnes in March, and was up 14.6 percent to 1.46 million tonnes in January-March.
China's Shenhua, Datong Group aim to reverse slide in coal exports
Two of China's largest coal producers -- Shenhua Group and Datong Coal Mining Group -- plan to revive their thermal coal exports to overseas customers, senior managers of the two companies said Thursday at the 13th Coaltrans China conference in Beijing.
China's thermal coal exports to neighboring countries in Asia have progressively declined over the past decade to 2.59 million mt in 2014.
But slowing growth in China's economy is creating a growing surplus for the domestic thermal coal market.
"We are trying to build our overseas customer base, and [our] exports are due to increase," Shenhua Group Vice General Manager Wang Xiaolin told the conference.
Xiaolin said Shenhua, China's largest producer of thermal coal, used to export large volumes of coal in the recent past but, "due to strong domestic demand, exports have come down."
Shenhua is also following a central government instruction to reduce its domestic coal production, Xiaolin said.
"We will reduce our output by 50 million to 60 million mt [in 2015]," Xiaolin said. "The [government] policy applies to all coal mines, and Shenhua is no exception."
Datong Coal Mining Group, another of China's larger coal producers, said it too is looking to re-engage with the seaborne market for thermal coal.
MGL: About a year ago we began to fret about China resuming coal exports. This is the first confirmation we've seen that this is plausible, it is worth recalling that Chinese coal is much closer to three big markets:- Korea, Japan and Taiwan that either Indonesian or Australian export coals. China exported 12m mt of coal a month as recently as 2001. Domestic demand in the go-go decade reduced these exports to zero, but today, coal is moving into structural surplus in China, that suggests exports.
China March rail coal transport down 11.5 pct on yr
China’s rail coal transport stood at 175.12 million tonnes in March, down 11.5% year on year but up 47.0% month on month, showed data from the China Coal Transport and Distribution Association on April 17.
In the first quarter, China transported a total 536.21 million tonnes of coal through railways, down 9.3% year on year, data showed.
Of this, 355.8 million tonnes or 66.35% of the total was railed to power plants, down 12.7% from a year ago, with March haulage sliding 14% year on year to 117.61 million tonnes.
Coal-dedicated Daqin line transported 35.81 million tonnes of coal in March, down 9.1% on year but up 11.91% on month. Total haulage between January and March dropped 6.3% year on year to 105.99 million tonnes.
Lower oil price, weaker Aussie dollar cut Rio's iron ore costs
Rio Tinto's iron ore cost of production has fallen from an average of $19.50 a tonne in 2014 to around $17 so far this year, the head of the world's second-largest mining company said on Thursday.
The reduction was thanks to a cheaper Australian dollar, which benefited Rio's giant iron ore mines in Australia, and a weaker oil price, Chief Executive Sam Walsh said during thecompany's annual general meeting.
Rio Tinto, the world's cheapest supplier of iron ore to China, as well as rivals BHP Billiton and Vale , are trying to cut production costs to the bone to remain competitive after a tumble in the price of iron ore in the last couple of years.
MGL: The radical shifts in the Oil price, Aus and Real exchange rates are making a nonsense of nearly all attempts at estimating cost curves right now. Its fair to say the entire cost curve of iron ore at the big 3 (4..) is falling, and its extremely difficult for outside observers to separate these macro effects from managements actions.
BHP's productivity initiative is noteworthy, as is Vale fall in costs as new high grade resource mines complete over the next 2 years. We've noted in the past that the big commodity declines tend to lose 60% in the first year, then suppurate at depressed levels for a number of years as new commodity on commodity competition sorts out the excess supply. We've seen this in coal, which most closely matches iron ore for its properties (high resource abundance, logistics dependence, low price point at customer)
Its a measure of our crazy world that Iron ore and Coal are now cheaper than horse manure. (~$100 delivered per tonne)
Rio Tinto to slash costs further to endure bumpy ride in iron ore
Rio Tinto, the world's second largest mining company, warned of "continued bumps" in its key iron ore market and vowed to stay focused on slashing costs to be the last man standing at a tough time for the sector.
The London-listed company and its rivals BHP Billiton and Vale are trying to cut production costs to the bone to remain competitive after a tumble in the price of iron ore in the last couple of years.
After losing almost three quarters of its value from a peak of about $190 per tonne in 2011, the outlook for the steel ingredient remains dire, due to a wave of new supply, mostly from the large producers themselves, smothering weaker demand growth.
"The reality is tough out there and as an organization all that we can do is to respond as best as we can in a tough environment," said Rio Tinto's Chairman Jan du Plessis at the company's annual general meeting.
Anglo-Australian Rio is the world's lowest-cost iron ore supplier and makes most if its profit from the steelmaking ingredient.
Its cost to produce each tonne of iron ore has fallen from an average of $19.50 a tonne in 2014 to around $17 this year thanks to a cheaper Australian dollar, which benefited Rio's giant iron ore mines in Australia, and weaker oil price.
"With iron ore now trading around $50 we have more to do to ensure that we maintain the margin between ourselves and the high-cost producers," Chief Executive Mark Cutifani said.
"Being the lowest-cost producer is not about a competition, or a bid to secure bragging rights. Rather, it's fundamental to the health of our business.
MGL: Iron ore used to be the most boring commodity. Prices were set each year. The big three made a nice gross margin thank you, the business gushed cash, but never grew. In a sense we're back to those days, the only problem we have is that we simply supply too much ore for a saturated market, and worse a market that shows little or no inclination to grow.
The big three want their market back, and everyone else is a target. The most pesky and obdurate is Fortescue, whose economics resemble their own, but whose ores are not as high in quality. We've done the price damage, we just wonder we move into the next phase of the market share war, which will focus on quality.
With the Chinese steel mills under the gun to reduce pollutants they will want clean, dry ore. Earlier this year we watched Exxon adroitly switch its capex commitments from upstream to downstream. They clearly went to major capex vendors and said"Look we don't need rigs and tube anymore, but our refineries and chemical complexes need all this funky engineered steels and valves, so instead of spending $XY billion on oilfield goods we'll spend the same on refinery and chemical equipement."
So which of the Iron ore boys are going to pull the same trick? They need to dry the ore (drying sheds instead of bulldozers), they need to beneficiate higher purity ore, can we lower the Silicates? Aluminium? and other nastys? My bet is there is some hard thinking at the big miners on how to narrow the 15% discount applied to most new production.
Vale is already talking about this in presentations:
Vale is gearing up to complete a bunch of mines over the next 18 months.
These mines bring:
~High grade (68% vs 55% for the Pilbara) ~Low impurity (Al/Si/Ph all lower by miles than Pilbara grades) ~Large consistent volume ore (critical for BF operators who dont want to have incessantly fiddle with their equipment)
Now we're not suggesting Vale reaps price reward for this material, but they will win market share amongst the pollution sensitive Chinese.
The Australian iron ore miners cannot sit suppine and hope, they have to raise grade and purity. That likely implies that volume growth goes, and mines start being re-examined for grade and purity.
Tata Steel says no deal with UK unions; strike ballot to go ahead
India's Tata Steel has failed to reach a deal with UK unions about its proposal to change the British pension scheme, it told India's National Stock Exchange on Thursday.
UK unions Community, GMB, UCATT and Unite will start balloting some 17,000 members over strike action from May 6, one day before the country's general election, they said in a joint statement earlier this week.
Should the strike go ahead, it would be one of the biggest industrial actions in the country in some 30 years.
"The negotiations ... have concluded without support from the trade unions on proposed modifications to the (pension) Scheme," Tata Steel said in response to a query from the Indian exchange.
The unions accuse Tata of not taking up their offer to re-enter discussions about the pension scheme.
"Our members are determined to stand up for their pension and therefore we have no option but to proceed to an industrial action ballot in May," said Roy Rickhuss, general secretary of Community, a major British trade union.
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