Oil and gas company ADX Energy has informed that the Italian Senate has passed a Bill to suspend oil and gas exploration activities in permits that have been approved or are in the process of being approved.
The suspension, if approved, would be for a period of up to 18 months to enable the government authorities to evaluate the suitability of exploration areas for sustainable hydrocarbon exploration and production activities (the Plan).
The bill is scheduled to be voted on in Parliament on the 12th of February 2019 and if enacted will become law, ADX said.
It is intended under the proposed legislation that the Ministries of Economic Development and Environment will review all areas in the Italian onshore and offshore territories to determine which are suitable for sustainable hydrocarbon prospecting, exploration and development activities (“E & P Activities”).
All areas will be assessed based on environment, social and economic suitability. Offshore areas will be considered on the basis of the potential effects on the ecosystem, as well as impacts on sea routes, fishing and potential interference with the coastal communities. Areas considered suitable for E & P Activities will resume activities. If The Plan is not enacted within two years activities will resume.
“Unfortunate setback”
ADX said: “ADX anticipates that the d 363C.R-.AX permit offshore Sicily containing the Nilde oil field given its distance from shore (53 kilometers) and its location in a benign sea environment in terms of sea bottom carbonate banks and associated life forms and will be judged appropriate for E & P operations. In order to minimize the risk ADX has requested a reduction in permit area by approximately 55% to minimize perceived impact.”
The reduced area will include the Nilde oil field, the Norma and Naila discoveries as well as the most prospective areas for future exploration.
“This is an unfortunate setback given the recent positive engagement with Italian Authorities following the provision by ADX to the Italian Authorities of farm in agreement documentation with a view to securing permit ratification (the “Decree”) as soon as practically possible,” ADX said.
On the positive side, ADX said, the Plan may result in a more efficient framework for achieving environmental approvals for operations in pre-approved areas. ADX said it would seek to secure a positive judgment on financial capability before any new law is enacted to provide greater certainty to its farmin partner SDP and other parties that have recently expressed interest in participating in the Nilde project.
“ADX will continue to keep shareholders informed in relation to the passage of the Bill through the Italian Parliament and its potential effect on the d 363C.R-.AX permit and the Nilde Redevelopment project,” ADX added.
As previously reported, ADX in October 2018 said it would farm out a 50 percent interest in the license to SDP Services Limited, who would fund a part of its work program in the 363 C.R-.AX Permit.
ADX then said SDP would fund the work program commitments of Audax Energy Srl (Audax) a wholly owned subsidiary of ADX up to a maximum of Euro 20.82 million to earn a pro-rata interest of 50% upon completion of funding. The farm-out is subject to the Italian Licensing Authorities ratifying the license.
Upon ratification of the License SDP will receive 5% net profits royalty interest attributable to any future production from the Nilde Field. ADX will remain operator of the license.
https://www.offshoreenergytoday.com/italy-to-suspend-oil-and-gas-exploration-activities/
A Brazilian court ordered miner Vale SA to suspend production at its Brucutu mine in Minas Gerais, which has an annual capacity of 30 million tonnes of iron ore, according to O Globo newspaper's website.
Vale, owner of the Brumadinho tailings dam which ruptured last month, killing more than 100 people, did not have an immediate comment. Brucutu is Vale's largest mine in Minas Gerais state.
South Korea has decided to lower taxes on LNG by as much as 74%, while raising taxes on thermal coal by 27%, from April this year as part of efforts to reduce the country's heavy reliance on coal in power generation, government officials said Friday.
"The government approved the tax rate revision so as to reduce consumption of coal blamed worsening air pollution," a senior official at the Ministry of Trade, Industry and Energy said.
Under the measure, taxes on LNG that include consumption tax and import tax will be lowered to Won 23 ($0.02) per kilograms from Won 91.4/kg currently, he said.
"Furthermore, import tax will be refunded for LNG used for combined heat and power," he said.
Whereas, taxes on thermal coal will further increase to Won 46/kg from Won 36/kg currently, he said. The rise came one year after the thermal coal taxes climbed to Won 36/kg in April last year from Won 30/kg previously.
"The new tax rates would be effective from April 1 this year," the official said.
"The tax rate revision is aimed to encourage consumption of the cleaner fuel in power generation by boosting LNG's price competitiveness against coal," the ministry official said.
The tax revision is in line with President Moon Jae-In's push for energy transitions from nuclear and coal to renewable sources and LNG.
"The tax revision is expected to increase the portion of LNG in power generation to over 20%, while reducing coal's portion to under 40%," the ministry official said.
Currently, coal-fired power plants generate a little more than 40% of the country's entire electricity supply, while LNG accounts for about 20%. Nuclear reactors provide about 30% with oil and renewable sources, such as hydropower, solar, wind and fuel cell, accounting for around 10%.
President Moon is pushing to reduce the portion of coal in the country's actual power production to 36.1% in 2030, while boosting LNG to 18.8% in 2030. The share of nuclear would also decline to 23.9% in 2030, while the share of renewables will account for 20% in 2030.
President Moon who took office in May 2017 has pledged to shut down ten aged coal-fired power plants before his five-year term ends in May 2022. Among them, four coal-fired power plants have been already closed, and two more will be permanently shut down by December this year.
The government has also pushed for converting some coal-fired power plants under construction into LNG-based ones.
The series of measure is expected to boost the country's LNG demand and LNG imports.
LNG sales by state-run Korea Gas Corp., which has a monopoly in domestic natural gas sales, jumped 12.6% to 36.22 million mt in 2018, compared with 32.16 million barrels in 2017, according to estimates by S&P Global Platts.
According to the Korea International Trade Association, South Korea's LNG imports reached an all-time high of 44.04 million tons last year, up 17.3% from 37.53 million mt in 2017.
Qatar was South Korea's largest LNG import source, accounting for 32.4% of the total. In particular, the LNG imports from the U.S. last year more than doubled to 4.66 million tons from 1.96 million tons a year earlier, the KITA said.
South Korea became the largest LNG importer from the US in 2018, outstripping Mexico, it said.
Shares of India’s Vedanta slumped to a two-and-a-half-year low on Friday after analysts expressed concerns over an investment by the parent company of the conglomerate in African miner Anglo American.
Vedanta said on Thursday its foreign unit Cairn India Holdings had paid $200-million to buy a stake in Anglo American from Volcan Investments, the miner's parent company, as a part of its "cash management activities".
The miner’s returns from the deal depends on Anglo American’s stock price and returns are not guaranteed, Morgan Stanley said in a note.
“While there is some downside protection for Vedanta in specific scenarios (not clarified by the management), returns are not guaranteed,” Morgan Stanley said.
The stock slumped as much as 19.86 percent on Friday, the largest intraday fall since October 2008. More than 74-million shares – 7.4 times its 30-day average - had changed hands by early afternoon, making it the most-heavily traded security on the NSE index.
Industry players too have speculated that Vedanta chairperson Anil Agarwal, who controls about a fifth of Anglo American, wants some form of a tie-up with the global miner.
In September last year, Agarwal’s decision to take the London-listed miner private was seen by some as a prelude to a potentially broader deal with bigger miner Anglo American.
Kotak’s analysts in a note said that while Vedanta stated the investment is to earn higher returns, they fail to see merit in the arrangement.
Industrial metals prices are set for their biggest annual fall in years after signs of slowing growth in China’s commodities-hungry economy and a US-China trade war, potentially affecting global mining firms.
Vedanta posted a 21.1% decline in third-quarter profit that still beat estimates.
http://www.miningweekly.com/article/indias-vedanta-sinks-20-to-2-12-year-low-2019-02-01
Sweden’s Alfa Laval reported quarterly order intake below market forecasts on Tuesday, dented by lower-than-expected bookings of its marine scrubbers, but forecast demand in the current quarter would be somewhat higher sequentially.
The maker of machinery such as heat exchangers, separators and ballast water treatment equipment said order intake grew 13 percent to 11.56 billion in the fourth quarter, missing the 11.94 billion forecast in a Reuters poll of analysts.
Alfa Laval is No. 2 behind Wartsila in selling marine scrubbers, which ship companies are buying to ensure their fleet is in compliance with stricter sulphur emission regulations coming into play at the start of next year.
It had forecast demand would rise somewhat in the fourth quarter, saying marine division orders were surging due to strong demand for scrubbers that strip sulphur as fuels are burned, allowing ships to continue using high-sulphur fuel oil.
“There was no change to the market’s view that the scrubber technology is a long-term financially attractive solution. Actual order intake was however lower after the extraordinary third quarter, when most suppliers filled up their backlog for delivery in 2019,” Alfa said in a statement.
The group’s adjusted earnings before interest, taxes and amortization (EBITA) rose to 1.79 billion Swedish crowns ($196.5 million) from 1.61 billion a year ago, but trailed the 1.98 billion seen by analysts.
Last week, Wartsila said it would shed six percent of its workforce to save 100 million euros a year by the end of 2020 as higher research and development and equipment delivery costs caused it to it missed quarterly profit forecasts.
Japan’s biggest trading house Mitsubishi Corp on Tuesday posted a 6 percent rise in its April-December net profit thanks to higher income from energy operations, and stuck to its record profit forecast for the year despite one-off losses.
Mitsubishi’s net profit grew to a record 442 billion yen ($4 billion) for the nine months to Dec. 31 from 416 billion yen a year ago.
The company booked an impairment loss of 28 billion yen on its stake in Singapore’s Olam International and 31 billion yen on its investment in iron ore mines in Chile in the October-December quarter, but it kept its forecast of a record 640 billion yen profit for the year ending March.
“We have paid a premium for Olam as we had expected synergy with our operations, but the outcome has missed our target,” Mitsubishi Chief Financial Officer Kazuyuki Masu told a news conference.
But Mitsubishi, which owns a 17.4 percent stake in Olam, has no plan to trim its stake in the Singaporean commodity trader and plans to seek more synergies in areas such as Africa, Masu said.
Olam said last month that it plans to invest $3.5 billion into key growth areas, such as edible nuts, coffee and cocoa, over the next few years, while exiting four existing businesses to raise funds.
As for the Chilean mines, Mitsubishi took the loss due to an extra environmental cost to build a tailing dam mainly for the Los Colorados mine, which produced 14 million tonnes of iron ore in 2018, and a repair cost for a broken shiploader at a port.
The port’s loading operation has been stopped since the collapse of the shiploader in November, Masu said.
The mines are 25 percent owned by Mitsubishi and 75 percent by Chilean iron ore and steel producer CAP SA, according to a Mitsubishi spokesman.
Mitsubishi’s annual profit prediction missed the 655 billion yen mean forecast in a poll of 9 analysts, according to Refinitiv.
Its nine-month profit was only 69 percent of its full-year estimate, but Masu said a special gain from its planned sale of two Australian thermal coal mines and stronger profits from some segments are expected to fill the gap.
Japanese trading companies have benefited from higher prices for commodities such as oil and coal, while their results also reflect healthy earnings in non-resource segments which they have strengthened since the last commodities down-cycle.
Southern California Gas (SoCalGas) on Tuesday warned it may have to curtail natural gas supplies and reiterated its plea to customers to use less of the fuel until further notice to avoid straining its system as cold weather blankets its service area.
The company issued a system-wide curtailment watch, which puts customers on notice that they “may be required to reduce their gas use if a curtailment is issued.”
SoCalGas later in the day announced a curtailment for power generation customers on the company’s system that would be imposed at 12 a.m. (0800 GMT) Wednesday, citing forecasts for low temperatures and high customer demand.
Gas supplies have been tight in Southern California this winter because of limitations on several SoCalGas pipelines and reduced availability of the utility’s biggest storage field at Aliso Canyon in Los Angeles, following a massive leak between October 2015 and February 2016.
After the leak, the state mandated Aliso can be used only to maintain system reliability after all other storage facilities and pipelines have been exhausted.
SoCalGas started pulling gas out of Aliso at the start of the year to avoid curtailing supplies to some non-core customers like electric generators and large industrial businesses.
The utility said it has continued withdrawing gas from Aliso to avoid removing too much fuel from its other storage facilities.
Overnight temperatures in Los Angeles are expected to drop as low as 38 degrees Fahrenheit (3 Celsius) Tuesday-Wednesday before rising to near normal levels later in the week, according to weather forecaster AccuWeather. The normal low in Los Angeles is 49 degrees at this time of year.
Consumer gas demand is expected to peak around 4.0 billion cubic feet per day (bcfd) on Wednesday and Thursday, up from 3.9 bcfd on Tuesday, according to SoCalGas. Last week, demand averaged 2.8 bcfd.
One billion cubic feet is enough to supply about 5 million U.S. homes for a day on average.
SoCalGas, a unit of Sempra Energy, said limitations the state imposed on Aliso were the primary reason supplies were tight.
The utility said Aliso limitations reduced supplies by over 1 bcfd, while ongoing work on three pipes, Lines 235-2, 3000 and 4000, resulted in a total reduction of about 0.7 bcfd.
SoCalGas can get about 2.7-3.3 bcfd from its pipes and the rest from storage, according to the state’s latest Aliso 715 report in July.
In total, SoCalGas has about 55.0 billion cubic feet of gas left in its four storage facilities, including Aliso, according to its website. That compares with 58.8 bcf at this time last year and a five-year (2013-2017) average of 60.3 bcf.
If we sell our shares, taxpayer will lose over £30bn
As RBS bosses yesterday sat down to their AGM with a plan to speed up the bank’s privatisation, the Labour Party repeated their intentions to halt the government’s botched sell-off.
Yesterday, Reuters reported that Labour’s shadow banking minister Jonathan Reynolds said that the party “cannot see the rationale for selling more shares” now, given that the share price is under what was paid and the bank is now paying out dividends to shareholders.
Indeed, the price of RBS shares remains around half the level they were when the government spent £45bn buying them up during the 2008 crisis.
In November 2018, the Office for Budget Responsibility estimated that the sell-off would therefore mean a loss of £28.5bn in public money.
What’s more, ditching RBS shares soon after they begin yielding a dividend is a further strike of economic incompetence. As the OBR also pointed out, the Treasury will be losing an additional £2bn in dividends with its sell-off plans.
But these losses are just one aspect of the argument against the RBS rip-off. By privatising RBS, the government will be losing much more than billions of pounds of public money. It will also be losing a huge opportunity to reshape Britain’s banking system into a force for good.
With RBS in public ownership, there is a huge opportunity for it to be transformed into a bank which actually works in the public interest.
The government could use its influence as majority shareholder to turn RBS into a vehicle for deploying better models of banking, by giving it a mandate to support local communities and the real economy.
The government could use its power to stop RBS creating money primarily to bid up prices for pre-existing property and other assets, and instead give it a mission to lend to socially useful projects, such as green infrastructure and quality, affordable housing.
This is why it is disappointing that the Labour Party seems to have rowed back from proposals to use the bank to direct investment in the UK economy. At least this is how Reynold’s words that “We don’t have a policy of day-to-day control of RBS” have been interpreted.
There is still hope for progressives who want to see government take real action on a banking sector which continues to prove unfit for purpose. As Reynolds says, “there is clearly unmet demand in lending and a problem with financial inclusion”, and options for reforming RBS have not been ruled out totally.
But it is worrying for activists that the Labour Party seems to be softening its proposals for radical financial reform. Reynolds has also hinted that the Party is considering ditching its Robin Hood Tax, which was welcomed as a way of reining in the financial sector’s excesses.
It is understandable that the Labour Treasury team seeks to steady the nerves of big finance, in order to avoid market movements which may put considerable pressure on a Corbyn government and its ability to transform the British economy.
But either way this is a fight that any government which wants to take the necessary steps to fix Britain’s broken economic model must prepare for. Rather than softening on the big banks, Labour must continue to be, in the words of Jeremy Corbyn, “a threat to a damaging and failed system that is rigged for the few”.
Simon Youel works on Positive Money’s influencing programme, focusing on media engagement and policy research
Deepwater drilling contractor Seadrill on Wednesday announced that it has entered into a 50/50 joint venture (JV) with Sonangol’s Empresa de Serviços e Sondagens de Angola.
The JV, which will function under the name Sonadrill, will operate drillships in Angola’s important deepwater basin for an initial period of five years.
Both companies will provide two existing drillships to Sonadrill. Sonangol’s drillships, Libongos and Quenguela, are currently being built at DSME shipyard in Korea. They are seventh generation high spec ultra deepwater drillships, and are expected to be delivered in the first half of 2019.
Seadrill will manage and operate the four drillships on behalf of Sonadrill. The company will also manage the delivery and mobilization to Angolan waters of the Libongos and Quenguela drillships under a separate Commissioning and Mobilization Agreement with Sonangol.
Seadrill’s CEO Anton Dibowitz said in a statement: “We are excited to have been selected by Sonangol to manage their newbuild drillships and to partner with them in pursuing opportunities in this important deepwater basin. Sonadrill will give us the opportunity to gain incremental access to a market that is expected to show significant growth over the next years, further strengthen our relationship with key customers and provides an attractive opportunity to continue expanding our fleet of premium ultra-deepwater rigs.”
The announcement is another sign of the renewed interest in Angolan oil and gas exploration and production, accompanying swift changes in the legal framework, spearheaded by president João Lourenço.
https://africaoilandpower.com/2019/02/07/seadrill-enters-joint-venture-with-sonangol/
Here is our Bayesian Timing System (BTS) analysis on the precious metals ETFs (GDX, GLD, SLV) as well as the dollar (UUP), oil (USO), natural gas (UNG), biotech (XBI), VIX (VXXB), financials (XLF), and Treasuries (TLT).
The BTS is neutral on metals -- GDX, GLD, SLV -- as they work on some type of top into a correction into the week of Feb 11. The more corrective this drop appears, the more the Bayesian probabilities build for a long signal next week that would target higher prices into March. Bottom line: The train hasn’t left the station for bulls; and one more quality entry should present themselves with very good RR attributes by the end of next week.
UUP: Signal Short. The important 25.60-ish level still determines the path higher or lower and at the moment, UUP is challenging this BP resistance from below and failed at the micro level on 1/25.
USO: Signal Short. Here are the BP paths: (1) [BP=21%] USO continues to push higher as though the train left the station, (2) [BP=46%] USO grinds higher, before a quick move down back into the mid 9s, and (3) [BP=33%] USO has a surprise trap door into the 8s. On the micro level, a BP cluster resides at 11.35-ish for the bears to get back in the game more imminently.
UNG: Signal Long. If this BP path proves out, then a shot back above 30-35 is in the cards…. A bottoming/reversal is expected the week of 2/4 headed into next week. From a bullish lens there are two paths to keep an eye on, of which both could occur: (1) UNG forms a false break of the 24 level, of which was broken on 2/4 – we are looking for 1-3 days below 24 and then a gap and run higher to begin and/or (2) From a BP cluster perspective an aggressive sharp spike into 22.75-23.25 could occur over the next week and then we rip higher for several weeks or more with an initial target at 30.
XBI: Signal Short. The most recent vibration window high zone continues to deter the bulls and on 2/5 it again served to reign in an attempted break higher; on the micro level there is getting below 82.75 and then 81to get that traction lower. Waiting for clues in this range…
VXXB: Signal Long. VXX’s replacement is VXXB – which triggered long on 1/28 using a hybrid mix of VXX and VXXB data. On the micro level, getting above 34.50 should get the ball rolling; on the support side there is a BP support cluster in the 32.75-33.25 that was hit on 2/5 and 2/6 –a turn higher for the next several weeks is most likely with a target in the 45-ish range...
XLF: Signal Short. Given the struggling uptrend over the last week, XLF continues to be stuck in no man’s land; and an ending diagonal seems like the most likely resolution to begin this week, with an initial target near 24.50-ish.
TLT: Signal Long. Simply put, the price pattern was the most attractive thing for this long signal – with the pattern since the 1/18 low presenting as a leading diagonal and the low on 2/4 as the deep retrace and then bounce higher into 2/5… upside BP cluster at 123-124 is in play and back below 120 is not ideal for the bulls.
Brazil’s mining agency plans to ban upstream tailings dams used for storing mining waste, a director at the National Mining Agency (ANM) said on Thursday, after such a dam burst last month, likely killing at least 300 people.
Eduardo Leão, a director at ANM, said the agency aims to issue an ordinance on Friday requiring that such dams be taken down or converted into other types of dams.
A tailings dam at a Vale SA iron ore mine in the southeastern state of Minas Gerais burst on Jan. 25, releasing a torrent of sludge that buried buildings and people. At least 150 people were killed and 182 are missing and presumed dead after the disaster in the town of Brumadinho.
Brazil has 88 upstream tailings dams, according to Leão. It was not immediately clear what kind of deadline the dam operators would face to take down or convert the dams.
The cause of the disaster remains unknown. A state regulatory official told Reuters last week that evidence suggested the dam burst because of liquefaction, a process where solid materials like sand lose strength and stiffness and behave like a liquid.
Vale’s dam in Brumadinho was built using the cheapest and least stable type of tailings dam design, known as an “upstream construction.” Upstream dams are waterlogged and therefore susceptible to cracks that can cause bursts.
A third-party audit of the dam conducted last year found cracks in drainage channels and recommended improvements in monitoring, according to the audit report reviewed by Reuters earlier this week.
MOSSEL BAY - French oil company Total and the government are on the hunt for oil in Mossel Bay in the Western Cape.
The company said the process is complex and expensive to find oil or natural gas.
Mineral Resources Minister Gwede Mantashe visited the operation on Saturday.
Shallow waters have been explored around the area but about 180 kilometres south of Mossel Bay in the Western Cape, deeper waters have remained untouched.
If oil or natural gas is found there it would be a boost for the country's economy.
Total has so far remained tight-lipped on the investigation.
Total general manager, Adewale Fayemi said, "at this point in time, we've drilled to the final depth...so now we are going start logging that data and after which we will see what exactly is there and then we will be able to communicate thereafter."
Total stopped drilling in 2014 due to mechanical problems caused by chaotic currents.
The oil giant had to import this rig, designed for operations in harsh environments, all the way from Norway.
Both Total and Mantashe say the country will know soon what mineral resource, if anything, has been discovered here.
There is a widespread concern in the world regarding China’s decelerating economic growth. The slowdown, if it continues, threatens economic activity almost everywhere. Growth in Germany, for example, has already cooled due to its exports of high-quality machinery to China dropping precipitously.
Those in the oil market also worry about China. The country’s economic growth has been a key driver of global crude oil consumption. Indeed, China accounts for one-third of the International Energy Agency’s projected 2019 increase in world oil use.
Weak Chinese economic growth is not the end of the oil market’s prospective ills, however. Few recognize the additional trouble on tap from the Chinese independent refiners affectionally known as “teapots.” The danger occurs because lower oil demand growth in China comes just when independent refining capacity there is rising. The capacity growth has been financed primarily by debt, most likely supplied by China’s alternative lenders. As demand slows, these refiners will turn to international markets, dumping products in Singapore, the Americas, or Europe to earn hard cash. In doing so, they could plunge the global refining industry into a serious recession and drive crude prices down sharply.
This will not be the first time that refineries in Asia caused a crisis in the oil sector. In 1997, Korean refiners did the same during the Asian financial collapse. That incident is described in the December 1997 Oil Market Intelligence (OMI). The report begins by noting that Korean refiners had begun to seek exports markets before the crisis hit “mostly to employ 620,000 b/d of new refining capacity that came on stream since late 1966.” The effort intensified as domestic consumption collapsed:
But once the won started its second descent in two years—it dropped over 94% against the dollar between July 1 and December 10 [1997], much of it in early December—the push to export became more desperate because the five big refiners could not recoup in domestic product prices the staggering dollar price of crude oil feedstock. (“Economic Crisis Spills Over onto Oil Markets,” Oil Market Intelligence, December 1997, p. 11.)
The article noted that Korean refiners were trying to sell products to China, Taiwan, and Japan. It added that Korea’s exports to China rose fourfold between January and October, while its share of the Chinese gasoil import market went from seven to twenty-six percent. The Asian refining center in Singapore lost market share, falling from seventy-five to twenty-six percent.Related: Oil Rallies As Saudis Cut Exports To The U.S.
The OMI report also observed ominously that “shippers and traders report that Korean refiners are lowering prices to meet their need to expand that share.”
The gasoil market suffered significantly. The OMI editors explained that Korea’s use was declining (consumption dropped one hundred fifty thousand barrels per day, or thirty-three percent, in December 1997 from December 1996), causing refiners to push gasoil to China. Those sales pressured margins at refineries in Singapore. The editors added, “If its [Korea’s] five refiners can keep importing crude oil—and the government is now talking of using foreign exchange reserves to finance crude purchases and overcome private credit squeezes—it is likely to keep pumping out the product to its neighbors.”
Looking back twenty years, one sees this is what happened. Figure 1 traces the price of gasoil and premium gasoline in Singapore by month from January 1997 to December 1999. Spot gasoil prices plunged from a peak of $32.50 per barrel in December 1996 to a low of $13.80 in October 1998. Distillate cracks measured against spot Dubai crude dropped from $9 per barrel in December 1996 to zero in 1999.
Arbitrage carried the impact of the Korean fire sale across the globe. Gasoil prices fell fifty-eight percent in Singapore from December 1996 to October 1998. In the US Gulf Coast market, they declined fifty-eight percent from December 1996 to February 1999. In Europe, the decline was fifty-one percent.
Korea’s fire sale of products precipitated a crude price decrease. As I have written often, product prices often lead crude prices. This was the case in the Asian crisis. Energy Intelligence Group data show that the netback on Dubai crude at Singapore declined from $23 per barrel in December 1996 to $9 in February 1999. Spot crude prices followed, as did prices for export contracts linked to spot crude prices.
Chinese independent refiners may be emulating the action of Korean refiners in 1997 and 1998. The Wall Street Journal warned on January 23 that the economic slowdown in China could curb Chinese gasoline consumption, which would “mean a flood of exports to the rest of Asia.” The WSJ author, Kevin Kingsbury, added that regional refining margins could be pressured.
Kingsbury explained that the economic slowdown would reduce growth in China’s oil consumption as refining capacity there increased:
Nomura forecasts demand growth of 0.5% this year, slowing from an estimated 4% last year. At the same time, Chinese refineries will increase production capacity by some 6%, according to Fitch Solutions.
He also noted that export quotas for gasoline, jet fuel, and fuel oil rose thirty-five percent last year. Further increases are expected for 2019 “so Chinese refiners can maintain production.”
In this regard, a January 24 report from Bloomberg is concerning. In it, Jack Wittels wrote that “a fleet of giant newly built oil tankers is gearing up to ship diesel out of East Asia.” Five new tankers are positioned off China’s coast, each with a capacity of two million barrels. Two additional tankers will shortly join the “armada.” Four of the parked vessels are already loaded or loading. The products will likely move to Europe, where margins are high.
These will not be the last shipments from China. In past economic downturns, the decrease in petroleum product consumption has lagged the falloff in economic activity. For example, the December 1997 OMI began its discussion of problems in Asia with this observation: “a few short months ago it seemed that Asia’s economic woes were unlikely to affect oil demand in a major way, and that the financial crisis could be contained in Thailand, Malaysia, Indonesia and the Philippines.” The article then continued ruefully, “Neither proposition looks valid anymore.”
The increased exports from China will reduce refining margins across the globe just as margins are being squeezed by a gasoline surplus and as refiners get ready to meet the IMO 2020 standard. This situation could have serious impacts on US and European refiners. Profits could come under intense pressure, particularly at firms that have been boosting product exports from the United States to Europe and the Americas.
Attention must stay riveted on China for the rest of 2019. The volume of product exports from its refineries will keep rising if its economy continues to falter, as many believe it will. The country’s problems, and problems for the world refining industry, will be compounded if the United States and China cannot resolve their trade war.
In this regard, further news on Wednesday, January 29, was ominous. Platts reported that China’s refiners are looking beyond Asia to boost exports. In 2018, Chinese gasoline exports rose twelve percent from 2017 and gasoil exports seven percent. There could be much larger increases in 2019 as more refining capacity comes on stream, especially if China’s domestic consumption stays the same or decreases.
https://oilprice.com/Energy/Oil-Prices/The-Next-Big-Threat-For-Oil-Comes-From-China.html
Enterprise Products Partners L.P. said on Thursday that a pipeline it is converting from shipping natural gas liquids (NGL) to crude oil will begin in February limited operations to ship crude from the Permian to the Texas Gulf Coast, potentially easing some bottlenecks in the basin.
“Enterprise is in the process of commissioning facilities related to the conversion of one of the Seminole NGL pipelines to crude oil service,” the company said in its 2018 results release on Thursday.
Enterprise expects the repurposed Seminole pipeline to begin limited operations next month and to become fully operational in April 2019.
The repurposed crude oil pipeline is planned to have a capacity to ship around 200,000 bpd, and the conversion of the pipeline is supported by a 10-year contract with firm demand fees, Enterprise Products said.
When it announced plans to repurpose one of its NGL pipelines to crude oil, Enterprise said in December 2017 that after the Seminole conversion is completed, the partnership would have a total crude oil pipeline capacity of more than 650,000 bpd from the Permian to its crude oil hub in the Houston area.
Enterprise Products’ announcement that the repurposed crude oil pipeline would begin limited service as soon as February comes a day after ExxonMobil, Plains All American Pipeline, and Lotus Midstream said that they would build a pipeline capable of transporting more than 1 million barrels per day of crude oil and condensate from the Permian in West Texas to the Texas Gulf Coast.
Magellan Midstream Partners LP has canceled plans to develop a stand-alone crude pipeline West Texas, the area of the nation’s top oil field as it considers a lower-cost project for the same region, an executive said on Thursday.
The Tulsa-based company plans to pursue a lower-cost project to meet shipper needs in an effort to be more capital efficient, its chief executive told investors on a conference call.
“It would be a much, much lower capital investment, and it would be a much more efficient way for us to source barrels into Longhorn (pipeline) for our customers,” Magellan Chief Executive Michael Mears said.
In 2017, Magellan estimated that the pipeline would cost $150 million. A write off of expenditures related to the project reduced fourth-quarter distributable cash flow by $9 million, an executive said on the call.
The Tulsa, Oklahoma-based pipeline operator had said in 2017 it would build a 60-mile pipeline from Wink to Crane, Texas to supply crude to its large, 275,000-barrel-per-day Longhorn crude pipeline. That line runs from the Permian Basin in West Texas to refining and export facilities in Houston.
The first trades in financial derivative contracts that settle against Platts Marine Fuel 0.5% assessments are offering early cues to a surge in global shipping fuel prices heading into 2020, market participants said Friday.
Derivative contracts settling against the Platts FOB Singapore Marine Fuel 0.5% assessments traded for the first time Thursday, according to block clearing data published on the CME Group website.
Market participants say the traded levels for the December 2019 contracts validate widespread expectations of sharply higher prices of shipping fuel next year as the International Maritime Organization's 0.5% sulfur cap for marine fuels takes effect from January 2020.
"It just shows how much stronger the market expects the value to go up by," a Singapore-based fuel oil trader with an oil major said. "I'd expect quite an active trading interest from counterparties now that we have seen the first trades go through."
Twenty lots, equivalent to 2,000 mt, of CME's December Mini Singapore FOB Marine Fuel 0.5% (Platts) futures were block cleared by the exchange Thursday. The first trade for ten lots of Mini Singapore FOB Marine Fuel 0.5% (Platts) Futures for December was reported at $500/mt.
The contract was likely traded as a spread against ten lots of Mini Singapore Fuel Oil 380 CST (Platts) December Futures that was submitted for clearing at $320/mt at the same time. A second trade for ten lots of FOB Singapore Marine Fuel 0.5% (Platts) futures was reported at $517/mt.
The reported spread trade indicates a premium of $180/mt for Marine Fuel 0.5% over Fuel Oil 380 CST futures contracts for December. In comparison, Platts spot assessments for FOB Singapore Marine Fuel 0.5% cargoes averaged at a premium of $37.24/mt in January over the corresponding 380 CST HSFO assessment.
"At the moment we see Singapore 0.5% fuels pricing around a 10% premium to 380 CST HSFO, but as we get closer to 2020 we expect 0.5% pricing will switch from 'HSFO premium' towards 'MGO discount'," S&P Global Platts senior analyst Alex Yap said. "In 2020, we expect 0.5% will price at a relatively narrow discount to MGO (Marine Gasoil), but at a very large premium to HSFO with much wider overall light-heavy spreads."
Platts assessed December 2019, 380 CST futures at $313.65/mt Thursday. Platts FOB Singapore cargo assessments reflect product loading 15-30 days from the date of publication and traders say the relatively small premium for Marine Fuel 0.5% now is reflective of market dynamics with little buying interest for compliant fuels from ship owners.
The lack of demand for 0.5% fuels currently has also been evident in the Platts Market on Close assessment process since Platts launched the assessment on January 2, with only oil major BP and Japan's Mitsui submitting bids on a few occasions. On the other hand, Platts has published several offers to sell Marine Fuel 0.5% cargoes from BP, Mitsui and Spain's Repsol over the same period, signaling greater selling interest.
"Premium of around $40/mt to high sulfur [fuel oil] is reasonable for a spot cargo now as there is no actual demand at the moment other than for low sulfur [fuel oil] from the utility sector," a Singapore-based fuel oil trader with a Chinese major said.
"We are likely to see 0.5% low sulfur bunker demand emerging only from the fourth quarter this year ... the spread is likely to widen from the second half of this year," he said.
Bunkering Portfolio Solutions
Traders say low-sulfur marine fuel demand had yet to emerge in the region even after Beijing imposed a 0.5% sulfur limit from January 1, 2019 for marine fuel burnt along its entire coastline, as much of the industry is complying by largely using low sulfur marine gasoil.
"Currently there just isn't [any] liquidity [and only] sporadic purchases of 0.5% fuel from ships time to time," a Singapore-based bunker trader with a European trading house said.
Platts new assessments reflect specifications for RMG fuels as defined by the International Organization for Standardization in document ISO 8217:2010 Petroleum products - Fuels (class F) - Specifications of marine fuels, but with a sulfur cap of 0.5%. The assessments reflect existing parameters for volume, delivery period, size and pricing basis for HSFO cargoes in Singapore and Fujairah.
The tight supply of low sulfur marine gasoil in South Korea continued into February, from January, on robust demand following the January 1, 2019 implementation of China's 0.5% bunker fuel sulfur limit along its entire coastline.
Market sources said there has been a shift in demand from MGO to LSMGO following the emission regulations.
"The demand for MGO is like nothing nowadays, most of our customers take LSMGO," a market source with one refiner said.
Vessels were understood to be taking LSMGO at South Korean ports before heading to China.
Supply was also short, with two refiners unable to offer the fuel in the spot market.
One of the refiners said the shortage was due to strong demand, coupled with the shortage of a blending component, which is necessary to lower the pour point in order to meet ISO's winter specifications.
"Sales volume of LSMGO doubled from December to January, [and] we couldn't even offer LSMGO for more than two weeks in January," the refiner said.
Market sources said the earliest supply date is expected to be February 10-11 onwards.
"[The tight supply situation] should ease around mid-February; early February there will still be shortage," a source said.
South Korea's delivered LSMGO prices have surged 22.4% from $534/mt on January 2 to $653.50/mt on February 2, S&P Global Platts data showed.
Norway has built a reputation as one of the calmest and most predictable corners of the global oil industry, but lately it’s been full of surprises.
During the worst downturn in a generation, from 2014 to 2016, companies would regularly exceed official forecasts as oil production rose in defiance of falling prices. More recently, with crude surging back to multiyear highs, they’ve run into trouble.
The Norwegian Petroleum Directorate now expects output to fall to a 31-year low in 2019, with production expected to be almost 60 MMbbl short of its previous forecast for this year and in 2018. That’s 80,000 bopd less than expected.
So what happened?
1. Maintenance backlog
One of the most frequently cited reasons for oil production missing forecasts in the NPD’s monthly updates through 2018 was maintenance shutdowns. Back in 2016, when output surpassed forecasts by 6%, oil companies cut maintenance outages. They insisted back then that the reductions were due to efficiency gains and weren’t creating a backlog.
“Maybe they’ve stretched it too far in terms of avoiding maintenance,” said Simon Sjothun, an analyst at consulting firm Rystad Energy AS. “It works in the first couple of years,” but it’s a “very realistic hypothesis” that they’re now picking up the slack, he said.
2. Glitches and delays
Technical challenges on platforms or under the seabed, and delayed output last year will also impact 2019, the NPD’s Director General Bente Nyland said in an interview.
Wintershall AG’s Maria is one example of a field that hasn’t performed as expected, while Equinor ASA’s Gina Krog, which also started up in 2017, is “probably on the list,” Nyland said.
The NPD declined to provide more details on individual fields before a broad resource update in February or March. Alv Bjorn Solheim, a V.P. at Wintershall’s Norway unit, confirmed Maria had produced less than planned, but declined to say how much. Equinor declined to comment on Gina Krog.
Postponed startups include Equinor’s Oseberg Vestflanken, which came online in October last year instead of a planned startup in the second quarter. After taking over the Martin Linge project from Total SA, Equinor also pushed back startup to the beginning of 2020.
3. Hubris and tiny fields
Both authorities and companies might have been too optimistic in their assumptions about reserves and production rates for certain fields, said Nyland. She declined to mention any examples, but the NPD recently said that Spirit Energy Ltd had cut the oil-reserves estimate for its Oda field, due to start producing by March, by about 30% to 33 MMbbl.
Pressured to improve profitability after crude prices fell in 2014, oil companies turned over every stone to cut costs and pick solutions that raised the resource count for their projects. That could have led some to take an excessively optimistic view on how many barrels they would be able to squeeze out, said Sjothun.
Oda is also a typical example of smaller developments, which make up an increasing part of the project pipeline in Norway as the North Sea becomes a more mature oil basin and exploration in the Arctic Barents Sea continues to disappoint. The trouble with small fields is that the operator often has less data about the reservoir under the seabed, because a project of a smaller size doesn’t warrant drilling numerous wells, Nyland said.
“Small fields are the most difficult to forecast,” she said. “On bigger fields you’ll have more wells before you make a final decision. On a small field, you think that one well might be OK, and all of a sudden it doesn’t deliver.”
A brighter future
To be sure, the abrupt slump in Norway’s oil production is temporary. The Nordic country will enjoy a spectacular bump in oil production in 2020 thanks to Equinor’s Johan Sverdrup field, which is scheduled to start production in November this year.
With as much as 3.2 Bbbl in oil reserves and production of as much as 440,000 bpd in its first phase, the giant North Sea field should in 2020 contribute to the biggest year-on-year increase in Norway’s output since the 1980s.
https://www.worldoil.com/news/2019/2/3/the-curious-case-of-norways-60-mmbbl-of-missing-oil
Russian oil production has not yet reached its peak and expectations that it could decline in the next few years are not justified, Alexei Sazanov, head of the finance ministry’s tax department, said on Monday.
Sazanov also said the government would take necessary steps if it saw risks of a decline in oil production.
Russia’s energy ministry said earlier that Russian oil output could fall significantly in the next few years if some tax and other measures are not taken.
Russia has embarked on its most significant oil tax regime overhaul in past decades by tentatively introducing profit-based tax and gradually cutting oil export duties.
The implementation of new regulations affecting marine fuel specifications will have implications for crude oil and petroleum product markets over the coming decade. Previous Today in Energy articles described these regulationsand the short-term implications for refining margins through 2020. Today’s article discusses the longer-term implications of the market changes projected in EIA’s recently released Annual Energy Outlook 2019, as the response to these regulations will likely involve changes to ships, marine fuels, refining, and some infrastructure in the next six to eight years.
The International Marine Organization’s (IMO) new regulations limit the sulfur content in marine fuels used by ocean-going vessels in international waters to 0.5% by weight starting in January 2020, a reduction from the previous global limit of 3.5% established in 2012. This lower limit will change the way bunker fuel (the fuel mix consumed by large ocean-going vessels) is consumed in the United States, which, according to AEO2019, accounted for about 411,000 barrels per day (b/d) in 2018. This volume represents 3% of total transportation energy use and 1% of total U.S. petroleum and liquid fuel use.
This upcoming change will have wide-scale repercussions for the shipping industry and refineries in the United States and worldwide. Globally, marine vessels account for a critical part of the global economy, moving more than 80% of global trade by volume and more than 70% by value. Marine vessels also consume about 4 million b/d of petroleum, 4% of total global oil consumption. As outlined in a previous Today in Energy article, there are three main pathways for meeting the more stringent sulfur content regulations:
Installing scrubbers to remove pollutants from ships’ exhaust so ships can continue consuming high-sulfur residual fuel oil
Switching to lower-sulfur residual fuel oil or blending with distillate fuel oil to achieve lower-sulfur fuel mixes
Switching from petroleum-based fuels to other fuels such as liquefied natural gas (Because this option involves retrofitting costs, it is likely to be constrained to new builds.)
Residual oil currently accounts for the largest component of bunker fuel. EIA projects that the share of high-sulfur residual fuel oil consumed by U.S. ocean-going marine vessels will quickly drop in the near term, from 58% in 2019 to 3% in 2020 because few ships currently have scrubbers installed or will have them installed by 2020. As some ships install scrubbers that allow them to consume higher-sulfur fuels, EIA expects the residual fuel share to rebound partially to 24% in 2022.
Switching to lower-sulfur residual fuel oil or higher distillate blends is likely to be a more common compliance option for U.S. vessels. EIA projects that the share of low-sulfur residual fuel oil consumed in the U.S. bunker fuel market will increase from close to zero in 2018 to 38% in 2020. Similarly, EIA projects that the need to use distillate in lower-sulfur bunker fuels will increase distillate’s share of U.S. bunkering demand from 36% in 2019 to 57% in 2020. After 2020, these fuels continue to account for relatively large shares of the fuels used in marine vessels.
EIA expects the use of liquefied natural gas (LNG) in U.S. marine bunkering to be limited in the next five years, reflecting the limited infrastructure available to accommodate LNG bunkering at U.S. ports. As infrastructure adapts, LNG’s share of U.S. bunkering grows to 7% in 2030 and to 10% in 2050.
Similar to the January Short-Term Energy Outlook (STEO) forecast, the AEO2019 Reference case projects that the U.S. refining sector will respond to the projected lower demand for high-sulfur residual fuel oils as well as increased demand for low-sulfur fuels in two ways: increasing refinery utilization and switching to lower-cost inputs.
Much of U.S. refining capacity, especially on the U.S. Gulf Coast, has downstream units that upgrade residual oils into more valuable and lower-sulfur products. These complex units can process heavier and higher-sulfur crude oils that yield large quantities of residual oils. U.S. refinery utilization increases to 96% in 2020 and remains between 90% and 92% after 2026 through 2050 in the AEO2019 Reference case as these refineries aim to convert heavy, high-sulfur crude oil and residual fuel oil into lower-sulfur fuels. This change results in both increased imports of unfinished oils and increased exports of lower-sulfur diesel and residual fuels to supply the global market.
A flotilla loaded with about 7 million barrels of Venezuelan oil has formed in the Gulf of Mexico, some holding cargoes bought ahead of the latest U.S. sanctions on Venezuela and others whose buyers are weighing who to pay, according to traders, shippers and Refinitiv Eikon data.
The Trump administration’s move to impose sanctions last week was meant to undercut support for Venezuelan President Nicolas Maduro by targeting the Latin American nation’s oil exports to the United States, the source of most of its foreign revenue.
The sanctions aim to block U.S. refiners from paying into PDVSA accounts controlled by Maduro - one reason numerous tankers are waiting in limbo off Venezuela with payments unclear. The United States buys 500,000 barrels of Venezuelan crude per day.
U.S. customers of Venezuela’s state-run PDVSA are required by sanctions to deposit payments into escrow accounts that have not yet been set up. The funds will be controlled by Venezuelan congress head Juan Guaido, whom the United States, the European Union and much of Latin America recognize as the country’s leader.
Neither the U.S. Treasury Department nor White House responded to requests for comment.
There were over a dozen tankers this week anchored in Gulf of Mexico or outside of Venezuelan waters, according to the Refinitiv Eikon data, as shippers await payment and delivery directions from buyers.
Traders said some of the cargoes were used as floating storage by buyers who took advantage of PDVSA’s open market sales ahead of sanctions. Others were held by trading firms struggling to find refiners willing to take the oil due to payment difficulties related to sanctions.
“There were many cargoes of Venezuelan crude already in the Gulf when sanctions were announced,” said a trader who deals with PDVSA. Others are stuck because holders “cannot find who to sell them to due to sanctions,” the trader said.
The tankers had been chartered by regular U.S. buyers of Venezuelan oil, including Chevron Corp, PDVSA’s refining unit Citgo Petroleum and Valero Energy, and trading houses that sell to refiners.
“Everybody is still working through the mechanics of things, still trying to figure out how freights are going to get paid and is sitting on the sidelines waiting for this to roll out,” said one ship broker on Monday who was not authorized to speak publicly.
Chevron and Valero declined to comment. Citgo did not respond to requests for comment.
Separately, a few tankers that had waited for weeks to lift oil bound for U.S. customers left the Venezuelan port of Jose over the weekend without loading, according to Refinitiv data.
The oil fleet in Gulf waters grew as a bottleneck earlier formed around Venezuelan ports by tankers awaiting authorization to load. PDVSA has said it will only sell to certain customers that prepay for cargoes.
Outside of U.S. waters, there were also tankers loaded with Venezuelan crude and idling in the Caribbean and Europe, the Refinitiv data shows.
The American Petroleum Institute reported late Tuesday that U.S. crude supplies rose by 2.5 million barrels for the week ended Feb. 1, according to sources. The API also reportedly showed that gasoline stockpiles climbed by 1.7 million barrels, while distillate inventories edged up by 1.1 million barrels.
Inventory data from the Energy Information Administration will be released Wednesday. On average, analysts surveyed by S&P Global Platts expect the EIA to report a rise of 3.7 million barrels in crude supplies. The survey also forecast supply increases of 1.7 million barrels each for gasoline and distillates.
Less foreign oil is reaching American shores, as OPEC production cuts kick in and U.S. sanctions on Venezuela curb its exports.
Crude shipments to the U.S. from OPEC and its partners fell to 1.41 MMbpd in January, the lowest in five years, according to data from cargo-tracking and intelligence company Kpler. Shrinking Iraqi imports and deep output cuts by Saudi Arabia fueled the decline.
At the same time, Venezuela’s exports to the U.S. dropped by nearly 30%. The kicker: Nearly half of it has yet to discharge into U.S. ports and U.S. sanctions may keep the rest of it on the water. Nearly 7.6 MMbbl of Venezuelan crude is floating in the Gulf of Mexico, according to Kpler.
https://www.worldoil.com/news/2019/2/5/opecs-oil-exports-to-us-fell-to-five-year-low-in-january
Such unintended consequences are happening faster than the Alberta government likely expected, and it should now plan for a "soft exit" from curtailments that is fair to producers, Williams said on a quarterly conference call.
"The rail economics are seriously damaged, and a lot of the rail movements are stopping or have stopped," he said. "That's going to have the opposite impact than what the government wants."
Alberta curtailed 325,000 barrels per day (bpd) in January to drain a glut of crude in storage that was caused by congested pipelines. The output cuts boosted Canadian oil prices from record lows last year, but Suncor and other producers that have ample pipeline space and refineries say the sharp correction harmed their integrated businesses.
The curtailments were applied fairly and saved jobs in the sector, said Mike McKinnon, spokesman for Alberta's energy minister. He said the government will monitor storage levels and adjust production levels as needed.
Williams said that the case for forced curtailments is likely to abate with seasonal maintenance shutdowns by oil producers during the second quarter, and with Enbridge Inc's Line 3 expansion likely to start filling for start-up later this year.
"You're going to see the pressure start to come off," he said.
Suncor's shares turned positive after Williams' remarks, and were up 0.6 percent at C$43.77 on Wednesday afternoon in Toronto.
Alberta eased the curtailments modestly for February and March. Its plan is to reduce the curtailments further to an average of 95,000 bpd through the end of 2019 once storage levels are sufficiently reduced.
Suncor's comments echo those of rival Imperial Oil Ltd, which said last week that it is ending nearly all crude by rail shipments because of the price impact of the curtailments.
Late on Tuesday, Suncor reported a quarterly loss due largely to a one-time charge related to how it accounts for inventory.
(Reporting by Rod Nickel in Winnipeg, Manitoba; Editing Grant McCool and Matthew Lewis)
By Rod Nickel
As concerns loom about a Permian oil pipeline overbuild, Plains All American did not rule out the possibility Tuesday of teaming up with another competing project for its recently confirmed 1 million b/d pipeline to the Texas Gulf Coast.
Plains is the latest midstream company to report fourth-quarter earnings in a cycle where the big question is whether the Permian is about to swing from having too little pipeline space to having a glut of it.
The Wink to Webster Pipeline joint venture announced last week by Plains, ExxonMobil and Lotus Midstream will carry batched crude and condensate from West Texas to Houston starting in the first half of 2021. Plains owns a 20% stake.
Asked if too many Permian pipelines were in the works, Plains CEO Willie Chiang said the company wanted to get to the point of ordering pipe for Wink to Webster and be in a position to move forward. Plains is leading construction and will operate the line.
"What that says is we certainly haven't eliminated an opportunity to make the project stronger, and conversations continue," he said. "At the base core of it, we've got pipe ordered, and we're ready to go."
The JV has ordered some 650 miles of domestically sourced 36 inch-diameter line pipe.
Plains' 585,000 b/d Cactus II crude pipeline from the Permian to Corpus Christi is on schedule for partial service in late Q3 and full service by April 2020, Chiang said.
In an update on the reversal of the 1.2 million b/d Capline crude system, Plains said it would be ready to ship light oil in Q3 2020, while heavy crudes would start shipping in early 2022.
The reversed system would give Canadian and US Mid-Continent crudes more access to export markets on the Louisiana Gulf Coast, with origin points near Patoka, Illinois, and Collierville, Tennessee. Owners include Plains Pipeline, BP Oil Pipeline and Marathon Petroleum.
Venezuela is preparing to shut more than a quarter of its already reeling oil production in the coming weeks, with US sanctions preventing state-owned PDVSA from importing diluent needed to extract its extra heavy crude, sources said Monday.
Sources at PDVSA told S&P Global Platts the company expects it will not be able to produce some 300,000 b/d of diluted crude oil (DCO) without supplies of naphtha that are blended with the thick, tar-like crude from the Orinoco Belt to make it transportable.
Production of conventional crude oils that do not need to be improved will continue, but given the deterioration of infrastructure and internal labor problems, even those volumes will see further declines.
As a result, Venezuela?s total crude output will fall to below 800,000 b/d by the end of February, the sources said.
Platts estimated the country pumped 1.17 million b/d in December in its most recent monthly OPEC production survey.
"There is internal rebellion in PDVSA," one source told Platts on condition of anonymity. "The vast majority of workers do not attend calls and refuse to comply with orders that could put their personal safety at risk."
The sanctions, imposed last week, are expected to block the roughly 120,000 b/d in diluent that the US ships to Venezuela from Citgo, PDVSA?s US refining subsidiary.
Reliance Industries is another main supplier of diluent to Venezuela, providing about 65,000 b/d under a swap arrangement, but analysts say the Indian refiner would likely shy away from business with PDVSA so that its US subsidiary, RIL USA, does not get impacted by sanctions.
China Oil is the other main supplier of diluent, shipping about 50,000 b/d as part of a loan agreement that China signed with Venezuela.
Even with diluent, PDVSA?s DCO has come under increasing criticism for its high water content and sediment, as well as delays to loadings and inconsistent cargo volumes.
"We do not have ships lined up waiting to load crude," another PDVSA source told Platts. "There are also no ships unloading imported products on our docks. PDVSA is being isolated without the possibility of selling or buying. That's the reality."
FUEL SHORTAGES
Venezuela's domestic refineries remain mostly idle due to lack of crude supplies and damaged equipment, with rampant fuel shortages in the country that could lead to rationing.
The 955,000 b/d Paraguana Refining Center was operating at only 20.6% capacity on Monday, according to a technical report seen by Platts, while the 187,000 b/d Puerto La Cruz refinery was only running at 11.8% of its capacity. The 140,000 b/d El Palito refinery has been shut entirely.
"Inventories are exhausted," a Paraguana operator told Platts. "There are gasoline and diesel inventories for less than two days. LPG inventories are also depleted. Nor is there any jet fuel."
The PDVSA-operated Isla Refinery on Curacao is facing dire straits, as well. The refinery had been a lifeline for PDVSA for processing crude and supplying Venezuela's market with refined products, but with the sanctions, it may have to be shuttered.
Tankers arriving at the refinery have refused to unload because of the embargo, and Isla has processed all of the crude it received in January.
Venezuelan oil minister Manuel Quevedo, a former brigadier general in the National Guard, late last week decreed that no tankers would be allowed to depart without prepayment of cargoes, but PDVSA customers are wary that the prepayments would violate US sanctions.
The situation has become so tense that National Guard troops last week tried to force the captain of the Citgo-chartered vessel Mambo, which arrived at the Cardon refinery in the Paraguana complex on January 29, to unload 140,000 barrels of ultralight diesel under threat of imprisonment, sources said.
The captain had been ordered by Citgo not to offload the diesel because it had not yet been paid for by PDVSA, which eventually produced a court order to have the cargo discharged, according to the sources.
The Mambo left Cardon on Sunday, according to Platts shipping tracking software cFlow, after five days in port and is now in the Caribbean Sea headed to Houston.
U.S. oil major ExxonMobil can’t stop finding oil in Guyana. After a string of discoveries in the past two years, the company on Wednesday said it had made two additional discoveries offshore Guyana at the Tilapia-1 and Haimara-1 wells, bringing the total number of discoveries on the Stabroek Block to 12.
The discoveries build on the previously announced estimated recoverable resource of more than 5 billion oil-equivalent barrels on the Stabroek block.
Exxon has said that the Tilapia-1 is the fourth discovery in the Turbot area that includes the Turbot, Longtail and Pluma discoveries. Tilapia-1 encountered approximately 305 feet (93 meters) of high-quality oil-bearing sandstone reservoir and was drilled to a depth of 18,786 feet (5,726 meters) in 5,850 feet (1,783 meters) of water. The well is located approximately 3.4 miles (5.5 kilometers) west of the Longtail-1 well.
The Noble Tom Madden drillship began drilling the well on January 7, and will next drill the Yellowtail-1 well, approximately six miles (10 kilometers) west of Tilapia-1 in the Turbot area. Baseline 4-D seismic data acquisition is underway.
“We see a lot of development potential in the Turbot area and continue to prioritize exploration of high-potential prospects here,” said Steve Greenlee, president of ExxonMobil Exploration Company. “We expect this area to progress to a major development hub providing substantial value to Guyana, our partners and ExxonMobil.”
The other discovery, Exxon said, was at the Haimara-1 well, which encountered approximately 207 feet (63 meters) of high-quality, gas-condensate bearing sandstone reservoir. The well was drilled to a depth of 18,289 feet (5,575 meters) in 4,590 feet (1,399 meters) of water. It is located approximately 19 miles (31 kilometers) east of the Pluma-1 discovery and is a potential new area for development. The Stena Carron drillship began drilling the well on Jan. 3 and will next return to the Longtail discovery to complete a well test.
Good news for FPSO players
ExxonMobil discoveries are also good news for suppliers and builders of floating production units, as the oil company has said there is potential for at least five floating, production storage and offloading vessels (FPSO) on the Stabroek Block producing more than 750,000 barrels of oil per day by 2025.
The Liza Phase 1 development is progressing on schedule and is expected to begin producing up to 120,000 barrels of oil per day in early 2020, utilizing the Liza Destiny FPSO, Exxon said.
Liza Phase 2 is expected to startup by mid-2022. Pending government and regulatory approvals, sanctioning is expected in the first quarter of 2019 for the project, which will use a second FPSO designed to produce up to 220,000 barrels per day. Sanctioning of a third development, Payara, is also expected in 2019, and startup is expected as early as 2023.
The Stabroek Block is 6.6 million acres (26,800 square kilometers). ExxonMobil affiliate Esso Exploration and Production Guyana Limited is operator and holds 45 percent interest in the Stabroek Block. Hess Guyana Exploration Ltd. holds 30 percent interest and CNOOC Petroleum Guyana Limited, a wholly-owned subsidiary of CNOOC Limited, holds 25 percent interest.
https://www.offshoreenergytoday.com/breaking-exxonmobil-strikes-two-more-oil-finds-offshore-guyana/
U.S. crude oil refinery inputs averaged 16.6 million barrels per day during the week ending February 1, 2019, which was 170,000 barrels per day more than the previous week’s average. Refineries operated at 90.7% of their operable capacity last week. Gasoline production decreased last week, averaging 9.9 million barrels per day. Distillate fuel production increased last week, averaging 5.1 million barrels per day.
U.S. crude oil imports averaged 7.1 million barrels per day last week, up by 63,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 7.5 million barrels per day, 7.3% less than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 625,000 barrels per day, and distillate fuel imports averaged 459,000 barrels per day.
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 1.3 million barrels from the previous week. At 447.2 million barrels, U.S. crude oil inventories are about 6% above the five year average for this time of year. Total motor gasoline inventories increased by 0.5 million barrels last week and are about 5% above the five year average for this time of year. Finished gasoline inventories decreased while blending components inventories increased last week. Distillate fuel inventories decreased by 2.3 million barrels last week and are about 4% below the five year average for this time of year. Propane/propylene inventories decreased by 2.6 million barrels last week and are about 4% above the five year average for this time of year. Total commercial petroleum inventories decreased last week by 3.4 million barrels last week.
Total products supplied over the last four-week period averaged 21.2 million barrels per day, up by 2.0% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.0 million barrels per day, up by 1.6% from the same period last year. Distillate fuel product supplied averaged 4.5 million barrels per day over the past four weeks, up by 6.4% from the same period last year. Jet fuel product supplied was down 0.5% compared with the same four-week period last year.
Lower 48 production unchanged
Exports up 926,000 bbls a day
Cushing up 1.4 mln bbls
A part of TransCanada Corp’s Keystone oil pipeline was shut on Wednesday after a possible leak in the St Louis, Missouri, area, according to three sources familiar with the matter.
It was unclear, however, if the leak was from the Keystone pipeline itself, traders said, adding that the Steele-City-to-Patoka line was shut.
“The release is stopped,” said an official from Missouri Department of Natural Resources, adding that the spill occurred north of the city of St. Charles.
“(We are) working to determine which pipeline has the leak... expect to conduct excavation of pipelines tomorrow (Thursday) to try to find the leak.”
Earlier, energy intelligence provider Genscape reported that flows in the Keystone-to-Steele-City pipeline had decreased to near 41,000 barrels per day from about 622,000 barrels per day.
Libya’s eastern leader Khalifa Haftar said his forces have taken the country’s largest oil field after pushing into the southwest as part of an effort to secure the region and its energy installations.
Haftar’s self-styled Libyan National Army, the country’s largest and best-organized military force, already controls the so-called oil crescent, a coastal area containing the major exporting terminals. Its push southward has raised concerns among his enemies and some participants in the oil market that Haftar will gain a stranglehold on the energy industry in a nation with Africa’s largest proven crude reserves.
Sharara, which can pump 300,000 barrels a day of oil, is a joint venture between Libya’s National Oil Corp., Repsol SA, Total SA, OMV AG and Equinor ASA. It has been closed since December by armed residents demanding better pay and investment in the remote area.
Haftar’s army urged the NOC to lift the force majeure in place at Sharara. Force majeure is a legal status protecting a party from liability if it can’t fulfill a contract for reasons beyond its control. However, the NOC hasn’t yet issued instructions to restart production at the field, according to people involved in the situation who asked not to be identified because they aren’t authorized to speak to media.
"Today our forces reached Sharara, in agreement with everyone at the field,” Ahmed Al-Mismari, the LNA spokesman, said in a televised news conference. “We are all Libyans, one Libyan army.”
Mismari said the LNA took the area without a fight but didn’t give an indication as to whether it would hand the field over to the NOC, nor when it expected to restart production. Officials at Libya’s NOC didn’t immediately respond to requests for comment.
Rival Powers Claim Command of City Near Libya’s Biggest Oilfield
Backed by Russia, Egypt and the United Arab Emirates, Haftar has built the main force opposing the United Nations-backed government of Fayez al-Sarraj in Tripoli, the capital. It’s too early to say what his southern power play will mean for Libya’s oil industry. But if his previous confrontation with the Tripoli-based NOC is a guide, the outlook isn’t encouraging.
Oil Production
Most of Libya’s crude shipments were suspended for weeks in June due to a standoff between Haftar and the NOC. Haftar had recaptured two important export terminals from rivals and transferred control of those ports and three others to an oil authority in eastern Libya that lacked international recognition. Markets were deprived of some 800,000 barrels a day, and Libya lost $930 million in sales.
The lack of clarity about what’s now happening in the south casts doubt on Libya’s plan to boost output to 2.1 million barrels a day by the end of 2021. The nation’s internal turmoil led the Organization of Petroleum Exporting Countries in December to exempt Libya from participating in global production cuts.
Clashes between rival militias, as well as political jockeying by parallel governments in the east and west, have stunted Libya’s efforts to revive output following the 2011 uprising that ousted Muammar Qaddafi.
Haftar’s announcement comes after a day of confusion and conflicting reports about developments in the region. Earlier in the afternoon, Sarraj’s government named Ali Kana, a member of the Tuareg tribe and senior commander in the south, as military chief of the southwestern city of Sebha. The Tripoli government had called on Haftar overnight to halt airstrikes in the area.
The LNA now controls Sebha and the town of Ubari and has reached the outskirts of nearby Murzuq, Mismari said, adding that the campaign would continue until all of Libya was secured.
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Guyana’s government Wednesday said that American supermajor ExxonMobil has found substantial oil and gas deposits in two more massive offshore wells, taking its tally to 12 with only two failures so far, a rate of discovery that is well above global averages a top official said.
Mark Bynoe, director of Energy at the Ministry of the Presidency, announced the two oil finds at the Talipia-1 and Haimara-1 wells in the southwestern portion of the Stabroek offshore bloc near Suriname.
But even as authorities begin to digest the continuing success of the Guyana oil field, authorities in neighboring Trinidad are beginning to wake up to the possibility of the oil and gas-blessed nation extending the outer limits of the country’s continental shelf to explore possible rich oil and gas fields in acerages near Guyana. Guyana’s so far proven fields are located about halfway between the two countries.
Trinidad’s Minister of Energy, Franklin Khan told an international conference in Port of Spain this week that the plan is to “extend our maritime jurisdiction seawards to the outer edge of our continental margin. This would be major development as it would extend our boundaries to areas in close proximity to the Guyana-Suriname Basin in which major hydrocarbon discoveries have already been made. This country, therefore, has an opportunity to increase its access to potential oil and gas resources. However, opportunities are like sunrises, if you wait too long you miss them. You can therefore be assured that we will pursue this matter aggressively,” he said.
Island production has in recent years fallen to less than 100,000 barrels daily. Petrotrin, the major refinery which produced oil and petroleum products for much of the Caribbean trade bloc in recent decades, closed late last year under the weight of debt, overstaffing and age among other issues, putting a massive dent in a sector, which had been producing oil for more than 100 years.
Down to the southeast in Guyana, meanwhile, ExxonMobil along with partners Hess Oil of the US and Nexen of China first discovered world class oil deposits in mid 2015, setting up a mad rush to Guyana by global oil companies such as Repsol, Tullow, Total and Chevrol among others largely because the Guyana basin has lived up to predications by the US Geological Surveys about holding up to 14 billion barrels of oil and being the second largest undeveloped oilfield in the world. Hammerhead-1, one of the more recent wells discovered, neighbors a concession owned by the UK’s Tullow oil and Eco Atlantic. The two say it is just a matter of time before oil gushes to the surface as Hammerhead is one of the largest of Exxon’s discoveries.
Exxon is planning to begin actual oil production by March next year but officials have said that it could be as early at October 2019 as the preparatory work is well advanced and the basin is the gift that keeps on giving. A massive Floating Production Storage and Offloading (FPSO) vessel will be here from a Singapore shipyard by June to position itself to store and distribute oil. The company said last month that sub sea work has already begun to connect wells via umbilical chords as it races to develop its highly successful oilfield. Initial production is slated at 120,000 barrels daily, moving up to 750,000 by 2025.
The new discovery has also fired up exploratory work in neighboring Suriname but it is yet to find any production offshore to add to the 16,000 barrels it produces daily from onshore wells in the west near Guyana. Experts say it is when and not if the country will find oil.
“The rate of these finds remains well above industry standards and continues to allow for further de-risking of the deep and ultra-deep one, but we still have a substantial way to go before we can confidently say the one has been de-risked. This continues to be positive news for the people of Guyana, but the real substance of these finds will come when all Guyanese are able to benefit from these discoveries, whether directly and / or indirectly,” Bynoe said. He said authorities have been advised that Exxon plans to bring as many as five massive FPSO in about five years to cater for oil production, storage and distribution to international markets. Drill ships will next target the Yellowtail-1 well, about six miles west of Talipia-1.
Posted 12:00 am, February 7, 2019
©2019
https://www.caribbeanlifenews.com/stories/2019/2/2019-02-08-bw-exxon-gushing-wells-cl.html
Indian cotton export will fall due to the low rainfall and pest attacks in cotton growing regions. Indian Cotton imports are expected to rise by 80%, said a senior official of the Cotton Association of India.
The drastic fall in the Indian cotton supply will benefit the United States, Brazil and Australia as these all nations will get an excellent opportunity to the intensify cotton supply in South Asia, particularly in China, Bangladesh, and Pakistan.
Atul Ganatra, the president of the Cotton Association of India said: “The production is not sufficient to fulfil local consumption. From March onwards imports will pick up.”
In 2017-18, India’s cotton import accounted for 2.7 million bales, noting increment of 1.5 million bales in relation to the previous year. The spinning mills imported 548,000 bales in the month of January. India imports cotton from three countries i.e. the United States, Brazil, and Egypt.
“Due to dry weather farmers were forced to uproot plants early. They couldn’t go for third and fourth picking,” Ganatra said.
India’s cotton production heavily depends on rainfall in Gujarat and Maharashtra. Last year monsoon season recorded less rainfall which led to pest attacks affecting per hectare yield. In the current year, India is expected to produce 33 million bales, 2.5 million bales less in comparison to the previous year prediction of 33.5 million bales. The fall in output will lead to less supply of cotton from India. “India’s exports could fall 27.5% from a year ago to 5 million bales, the lowest level in a decade”, Ganatra said.
Indian farmers have not been able to cope with the rising problem of pest attacks, even with the help of pest-resistant Bt Cotton.
More News at EurAsian Times
https://eurasiantimes.com/indian-cotton-imports-to-rises-by-80-cotton-association-of-india/
Marathon Petroleum Corp posted a 56 percent jump in the number of barrels of crude it processed per day during the fourth quarter and the refiner’s margins rose, helped by access to cheap oil from Canada and its purchase of rival Andeavor.
At its refineries in the U.S. Midwest, Marathon has been processing large amounts of Canadian crude, which has turned cheaper relative to the benchmark West Texas Intermediate, because of transport bottlenecks and a storage glut in Canada.
Refiners such as Marathon process crude into diesel, gasoline and other products. Some of them faced here challenges after the United States imposed sweeping sanctions on Venezuela's state oil company PDVSA.
In November, Marathon Chief Executive Officer Gary Heminger said the company was importing more than 500,000 barrels per day of Canadian crude.
On Thursday, the Findlay, Ohio-based company said refining and marketing margin per barrel of oil jumped about 15 percent in the fourth quarter. Crude oil throughput rose to about 3 million barrels per day from 1.84 million barrels last year, helped by its acquisition of Andeavor.
Marathon agreed to buy Andeavor for more than $23 billion last year, to become one of the world’s largest refiners. The deal was closed in October.
“We have realized $160 million of synergies in just three months and continue to expect total annual gross run-rate synergies of up to $600 million at year-end 2019,” CEO Heminger said in a statement.
Income from its retail unit, which includes Speedway gas stations and convenience stores, rose more than four times to $613 million.
The company made a margin of 32.35 cents per gallon at its stores, compared with 17.72 cents last year.
“Relative to our estimate, the beat was roughly split between refining and retail, two areas that benefited from the extreme drop in crude prices in the quarter,” analysts at Tudor, Pickering and Holt said.
Marathon’s adjusted profit of $2.41 per share beat the energy investment firm’s estimate of $2.24 per share.
Net income attributable to Marathon fell to $951 million, or $1.38 per share, in the fourth quarter ended Dec. 31, from $2.02 billion, or $4.13 per share, a year earlier.
In the year-ago quarter, the company recorded a $1.5 billion gain related to the U.S. tax overhaul.
Total revenue rose to $32.54 billion from $21.24 billion.
Legislation that would allow the U.S. government to sue OPEC for inflating oil prices cleared a key hurdle in the new session of Congress.
The House Judiciary Committee, now led by Democrats, advanced the “No Oil Producing and Exporting Cartels Act" Thursday. That sets the bipartisan "NOPEC" bill, which would subject the cartel to possible antitrust action by the Department of Justice, up for a possible House vote. A similar bill targeting OPEC was introduced in the Senate on Thursday.
OPEC’s members “deliberately collude to limit crude oil production as a means of fixing prices, unfairly driving up the price of crude oil," House Judiciary Committee Chairman Jerrold Nadler said before voting in favour of the legislation. The law would amend the Sherman Antitrust Act of 1890, the law used more than a century ago to break up the oil empire of John Rockefeller.
Various iterations of the bill have been proposed in the past, and former presidents have threatened to use their veto power to scupper the legislation. But President Donald Trump could be more amenable, given his frequent twitter attacks accusing the group of keeping oil prices artificially high.
“I’m not going to predict it will get passed and enacted into law, but I think its prospects are pretty good,” said Seth Bloom, former general counsel of the Senate Antitrust Subcommittee. “OPEC doesn’t have too many friends right now and the legislation may likely have a friend in the White House given Trump has written favourably about it in the past."
U.S. Assistant Attorney General Makan Delrahim told members of a House subcommittee in December the administration “continues to study” the legislation.
“If OPEC members conducted the same manipulation in the United States that they practice in Vienna, they could be prosecuted,” said Robbie Diamond, who heads up Securing America’s Future Energy. “Their actions have a profound impact on U.S. consumers, businesses and our military, and our government can no longer allow that.”
https://www.worldoil.com/news/2019/2/7/anti-opec-bill-allowing-us-to-sue-oil-cartel-moves-forward
NEW DELHI: State-owned oil firms' capital expenditure has hit a four-year low with PSUs such as ONGC and IOC planning to invest Rs 93,693 crore in oil and gas exploration, refining and petrochemicals in the 2019-20 fiscal year.
The capital expenditure outlay of Oil and Natural Gas Corp (ONGC), Indian Oil CorpNSE -1.06 % (IOC), GAIL (India) Ltd, Bharat Petroleum Corp Ltd (BPCL), Hindustan PetroleumNSE -3.31 % Corp Ltd (HPCL), Mangalore Refineries and Petrochemicals Ltd and their subsidia ..
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It takes three things to bring a vibrant emerging market economy to the brink of collapse: corruption, revolution, and inflation.
Venezuelans have seen all three, unfolding over time, though not necessarily in that order.
They have also seen a long list of failed policies pursued by all sorts of right and left-wing revolutionaries, from Perez to Chávez, and Maduro -- all of whom can take their fair share of blame for bringing a country rich in natural and human resources to the brink of collapse.
Venezuela’s playbook of the sum of all failed policies begins with a wave of nationalizations and labor market regulations back in the late 1970s, “long before Hugo Chavéz came to power, making conditions even worse,” says Dr. Rainer Zitelmann, sociologist, historian and author of the upcoming book, The Power of Capitalism. “One of the reasons for Venezuela’s problems was the unusually high degree of government regulation of the labor market.”
That set in motion a race for further, tighter, labor market regulations.
“From 1974 onwards, the applicable rules were tightened even further to a level that was unprecedented almost anywhere else in the world – let alone Latin America,” explains Zitelmann. “From adding the equivalent of 5.35 months’ wages to the cost of employing someone in 1972, non-wage labor costs soared to add the equivalent of 8.98 months’ wages in 1992.”
The playbook continued with the price controls and heavy subsidies under RafaelCaldera (president twice, from 1969-74 and 1994-99) and his strange bedfellows. They made crude oil cheaper than water, and widened the government deficit -- adding to soaring government debt.
Wait, there’s much more.
There are the currency controls that favored foreign manufacturers over domestic manufacturers.
And there was the modern version of Bolivarian socialism, which borrowed a page of two from Castro’s Cuban Socialism, and from Che Guevara’s and Salvatore Allende’ Anti-Americanism, to add to the woes of Venezuela’s economy.
“After Hugo Chávez’s death in 2013, Nicolás Maduro, his successor and former second-in-command, accelerated the nationalization of dairies, coffee producers, supermarkets, manufacturers of fertilizers and shoe factories,” says Zitelmann. “Production buckled or stopped entirely.”
Things turn worse when the price of oil collapsed. “Then the oil prices plummeted, losing almost 50% of their value within a single year from USD 111 per barrel in late 2013 to USD 57.60, then dropping to USD 37.60 another year later and fluctuating between USD 27.10 and USD 57.30 in 2016,” adds Zitelmann.
To be fair, the collapse in oil prices had a devastating effect on every major oil producing nation. But they were amplified in the case of Venezuela, according to Zitelmann.
“While this would have caused a predicament for any oil-producing nation, these problems were amplified in a country with an extremely inefficient socialist economy and strict price controls,” he notes. “The fatal effects of Chávez’s socialist policies became obvious once and for all and the entire system fell apart. As had become evident in other countries, it was apparent that, far from being an efficient means to fight inflation, price controls only make things worse.”
That’s how Venezuela ended up with skyrocketed inflation. “Inflation reached 225% in 2016, higher than anywhere else in the world except for South Sudan,” says Zitelmann. “It was probably close to 800%, accompanied by a 19% drop in economic output in 2016, according to an internal report by the Governor of the National Bank.”
Economists know too well what follows in this situation. “People started hoarding all sorts of things that were sold very cheaply and would frequently queue for hours to buy something they would then sell on at a much higher price on the black market,” explains Zitelmann. “In sum, again a socialist experiment was attempted, and again it failed, as all other socialist experiments have done in the last 100 years.”
And the people of Venezuela are paying dearly, as the country is at the brink of collapse.
New and relocated industrial units in the economic zones will be given uninterrupted power supply, Nasrul Hamid, state minister for power, said yesterday.
He said industrialists should not worry about the availability of power as the generation capacity is increasing.
“There are about 4,000 megawatts of unused electricity at this moment and the government is paying for it,” he said while addressing a programme at The Westin Dhaka hotel.
The Federation of Bangladesh Chambers of Commerce and Industries (FBCCI) organised the institutional dialogue styled “Success in power generation: best use of power in achieving dynamic growth”.
Bangladesh's installed power generation capacity is 20,854MW. Actual generation was 8,744MW yesterday, according to the power division.
“There is no power shortage in the country,” said the state minister.
He, however, said the government faces challenges in ensuring quality power transmission. The state minister also said entrepreneurs would not get gas and power connections if they set up industries in an unplanned manner.
Hamid said imported power is cheaper than locally generated one. It needs $1.5 billion in investment to generate 1,000MW of power.
Salman F Rahman, private industry and investment adviser to the prime minister, said the economic development of the country has improved in the last 10 years thanks to the advancement in power generation.
“We have to achieve double-digit growth within next five years though it is really difficult,” he said.
The businessperson said the private sector is the only engine that can help the country pull off the targeted economic growth.
“So, we have to remove all kinds of bottlenecks in achieving the growth target.”
The adviser said the new cabinet is giving emphasis on businesses for further growth.
Shafiul Islam Mohiuddin, president of the FBCCI, said private investment is not increasing at an expected rate due to unpredictable power tariff and bank interest rate.
He urged the government to give hints in advance about any power tariff plan to help investors take informed decisions on expanding businesses.
Ahmad Kaikaus, secretary of the power division, said the government has set a target to increase the installed power generation to 60,000MW by 2041.
Sheikh Fazle Fahim, senior vice-president of the FBCCI; Humayun Rashid, managing director of Energypac; Moin Uddin, chairman of Bangladesh Rural Electrification Board; Md Helal Uddin, chairman of the Sustainable and Renewable Energy Development Authority, and Mohammad Mejbahuddin, chief executive officer of the power division of United Group, were present.
https://www.thedailystar.net/business/news/economic-zones-factories-get-uninterrupted-power-1697182
BRASILIA – Petrobras has put the finishing touches on the first wave of development at the massive offshore Brazil Lula Field, pumping first oil from the latest floating production unit to be installed at the country’s largest oil and natural gas producer, the company announced on Friday.
The FPSO P-67 floating production, storage and offloading vessel, or FPSO, is the ninth FPSO installed at Lula and officially ends the first phase of development at the field, state-led Petrobras said. The FPSO, which was installed at the Lula Norte area, has installed capacity to produce 150,000 b/d and process 6 million cu m/d, according to Petrobras.
“The Lula Field, which includes the Lula and Cernambi reservoirs, is the country’s biggest producer and should reach the mark of 1 million barrels of daily production in 2019, less than a decade after commercial production started in October 2010,” Petrobras said in a statement. Lula produced 902,918 b/d and 38.2 million cu m/d in November, according to the latest data from Brazil’s National Petroleum Agency, or ANP.
Iniciamos, com nossos parceiros, a produção de petróleo e gás natural, na P-67, no pré-sal da Bacia de Santos. Assista o vídeo com os detalhes sobre a plataforma: https://t.co/eIGkbU3OY8 — Petrobras (@petrobras) February 1, 2019
Lula was the first of several multibillion-barrel discoveries found trapped under a thick layer of salt more than 7,000 meters deep in the Campos and Santos basins off the coast of Brazil in the mid-2000s to enter production. Petrobras and its partners have since started output at the Sapinhoa and Buzios fields, with growing output from the region known as the subsalt expected to make Brazil one of the world’s top 10 oil exporters by the middle of the next decade.
The ANP expects the country’s output to reach 7.5 million b/d by 2030, driven by discoveries currently under development as well as new production derived from areas sold off at concession bid rounds and production-sharing auctions held in 2017-2018. Exports are expected to climb to 4 million b/d from 1.1 million b/d currently, according to the ANP.
The FPSO P-67 will be anchored in waters 2,130 meters deep about 260 kilometers off the coast of Rio de Janeiro state, Petrobras said. Output will be handled via nine production wells, while the FPSO will also be connected to six injection wells.
The vessel’s production will be offloaded in ship-to-ship operations via tanker, while gas output will be exported via several subsea pipelines. Petrobras recently connected a new tranche of the Route 1 offshore pipeline to the Mexilhao platform, which should help boost gas exports from subsalt fields such as Lula.
Petrobras owns a 65% operating stake in Lula, which is located in the Santos Basin’s BM-S-11 block. Shell holds a 25% minority share, while Portugal’s Galp Energia retains the remaining 10%.–MercoPress
Asian spot prices for liquefied natural gas (LNG) fell to a nine-month low this week as the region remains oversupplied amid a warmer-than-usual winter. Spot prices for March delivery to Asia this week fell to $7.00 per million British thermal units (mmBtu), down $1 from the previous week, lowest since April 6, trade sources said.
They are also seasonally at the lowest for this time of the year since 2016, Reuters data showed.
Oil major BP offered a cargo for March 26 to 28 for delivery into Japan, South Korea, Taiwan or China at $7.10 per mmBtu during the Platts pricing process on Thursday, industry sources said.
Asian prices for March cargoes have fallen below the UK front-month gas price, reversing a multi-year trend in which Asian prices had a premium over Europe and prompting some traders to redirect cargoes to Europe from Asia.
Vitol on Wednesday changed the destination of two LNG cargoes sourced in the United States to northwest Europe from Asia due to the discount on Asian prices compared to those in Britain, an industry source familiar with the matter said.
“The market’s getting kind of crazy,” a Singapore-based industry source said, adding that derivatives volumes in Asia have dropped recently.
Trade was also quiet ahead of week-long Chinese New Year holidays, when most dealers from the world’s second largest LNG importer will be away, amid a production shut down at factories.
Gail (India) sold six LNG cargoes from Cove Point and Sabine Pass terminals in the United States for loading in 2020, industry sources said. Price details could not immediately be confirmed but there were several buyers including Glencore, the sources added.
It has also offered two more tenders offering more cargoes for next year.
The Indian importer has 20-year deals to buy 5.8 million tonnes a year of U.S. LNG, split between Dominion Energy’s Cove Point plant and Cheniere Energy’s Sabine Pass site but is likely selling the cargoes as part of optimization, one of the sources said.
Papua New Guinea LNG plant may have sold its cargo for March delivery at about $6.50 per mmBtu on a free-on-board basis while Sakhalin LNG may have sold its March loading cargoes at below $7 per mmBtu, a second source said. The deals could not immediately be confirmed.
Offering some support for prices, Chevron Corp’s Gorgon LNG project’s train 3 remains shut after production was halted at the train in mid-January due to a mechanical issue, industry sources said.
China’s state energy giants are set to raise spending on domestic drilling this year to the highest levels since 2016, focusing on adding natural gas reserves in a concerted drive to boost local supplies.
Responding to President Xi Jinping’s call last August to boost domestic energy security, China’s trio of oil majors - PetroChina, Sinopec Corp and CNOOC Ltd - are adding thousands of wells at oil basins in the remote deserts of the northwest region of Xinjiang, shale rocks in southwest Sichuan province and deepwater fields of the South China Sea.
Firms are showing greater risk appetite, expanding investments faster in exploration than production, emboldened by Beijing’s political push and oil near $60 a barrel, said state oil executives and analysts at consultancy Wood Mackenzie.
“We shall carry through resolutely the State Council’s call on stepping up domestic exploration and development and launch an offensive war,” PetroChina Chairman Wang Yilin was cited as saying in an inhouse newspaper in December.
Offshore specialist CNOOC Ltd said last week it was confident of achieving its spending target this year, the highest since 2014. It pledged to spend twice as much this year in domestic exploratory drilling as in 2016.
“With oil prices at $50, $60 and $70...we’re making decent profits,” Yuan Guangyu, CNOOC’s Chief Executive Officer, said last week.
CNPC, Asia’s largest oil and gas producer and parent of PetroChina, is boosting risk exploration investment five-fold to 5 billion yuan ($741 million) this year from 1 billion yuan last year.
But with oil reservoirs maturing and new discoveries tending to be smaller and more costly, even more drilling is unlikely to reverse China’s declining oil outlook, analysts say.
China, set to remain the world’s top oil buyer for years to come, is forecast to slip to the 10th largest global oil producer in 2020, down from No.5 for most of last decade, said Wood Mackenzie.
“China will likely continue on the same path as it has in recent years – an overwhelming focus on new gas production, leading to continued decline in its oil output,” said Angus Rodger, research director of Asia-Pacific upstream at Wood Mackenzie.
PETROCHINA LEADS PUSH
With Beijing pushing to reduce energy import dependence and hit environmental targets, gas output is forecast by analysts to rise at 6-8 percent a year through 2020.
China, the world’s No.3 gas consumer, overtook Japan as the world’s top gas importer in October.
PetroChina, which produces some 70 percent of the country’s gas output, will lead the drive, adding thousands of wells in southwestern Sichuan, northern Ordos and northwest Tarim basin, CNPC says on its website.
The major is also ramping up shale development in Sichuan, seeking to catch up with Sinopec Corp which has pioneered China’s nascent shale push. Despite almost a decade of drilling, shale makes up just 6 percent of China’s total gas output because of complex geology and high costs of development.
PetroChina raised its shale gas output 40 percent last year to 4.3 billion cubic meters, while Sinopec’s production was largely flat at 6 bcm.
“Controlling the largest and best acreage, CNPC has been ramping up aggressively capital and human resource deployment over the past 3-4 months in Sichuan shale,” said Woodmac analyst Max Petrov who tracks Chinese majors’ investment.
Sinopec declined comment. CNPC did not respond to Reuters’ request for comment.
DEEPWATER
Beyond 2020, deepwater discoveries in the South China Sea, such as Linghui 17-2, some 150km (90 miles) off China’s southernmost province of Hainan, will lend growth to China’s gas portfolio.
With estimated proven recoverable reserves of 2.5 trillion cubic feet, Lingshui is CNOOC’s single-largest fully owned deepwater gas discovery. BG Group walked away with little success after exploratory drilling at the nearby Lingshui 22-1-1 well in 2010.
Aiming to add 50 percent to gas reserves by 2025, CNOOC is expected to step up drilling in the deepwater acreage of the Pearl River Mouth basin and expand earlier major discoveries including Yacheng and Dongfang, both near Hainan province.
“Natural gas is becoming increasingly popular under the government’s green push. And its relatively less risky than oil under long-term off-take deals,” said a state oil executive.
Companies, however, will hold off drilling in disputed territorial waters of the South China Sea due to technological challenges and the lack of experienced global partners willing to risk exploring those areas, analysts said.
Beijing claims about 90 percent of the South China Sea, whose estimated energy potential varies widely, although geologists believe it holds more gas than oil. Vietnam, the Philippines, Malaysia, Brunei and Taiwan also claim parts of the key waterway.
SHORT RESERVE LIFE
Sinopec, traditionally a refiner rather than a driller, has the smallest resource base and may lag its peers, analysts say.
Sinopec’s proven oil reserves by end-2017 could last less than six years of production, versus CNOOC’s 10 years, while Sinopec’s gas reserve life of 8 years is dwarfed by PetroChina’s 24 years, according to calculations based on company filings.
Sinopec is expected to boost spending this year, including in developing its second shale gas target, Weirong block, in Sichuan. But the momentum of making new finds is waning, said company officials.
“Sinopec is well aware of its problems, but the will to change that seems to have a bottleneck at the top as the company sees itself more of a downstream, petrochemical player,” said Woodmac’s Petrov.
Baker Hughes on Friday reported that the number of active U.S. rigs drilling for oil fell by 15 to 847 this week. That followed an increase of 10 in the oil-rig count a week earlier. The total active U.S. rig count also declined by 14 to 1,045, according to Baker Hughes.
U.S. oil and natural gas producer Chevron Corp on Friday reported quarterly earnings that topped analysts’ estimates on higher prices and production, sending shares higher in premarket trading.
Results for the San Ramon, California, company reflected a 12.5 percent increase in oil and gas production as net output added 156,000 barrels per day (bpd) from a year earlier to 3.08 million bpd. Prices paid for its crude rose to $59 a barrel in the quarter, from $57 a year earlier, the company said.
Chevron’s cash flow from operations rose nearly 51 percent to $30.6 billion, reflecting the higher output and expense reduction. Investors have been pushing oil companies to restrain spending and increase returns to shareholders.
The company this week announced it would raise its dividend to $1.19 a share from $1.12 per share.
Chevron reported a profit of $3.7 billion, or $1.95 per share, compared with $3.11 billion, or $1.64 a share a year earlier Analysts’ mean forecast was $1.87 a share, according to Refinitiv.
Business unit results compared to the year-ago period were lower because of the impact of U.S. tax reform a year ago. Profit from oil and gas exploration was $3.29 billion compared with $5.29 billion a year earlier; refining profit fell to $256 million compared with $1.2 billion a year ago.
Oilfield services provider Weatherford International Plc reported a bigger-than-expected quarterly loss on Friday, as a fall in expenses failed to make up for lower revenue from markets including the Middle East and Africa.
The Houston-based company, which has not reported a quarterly profit in four years, has struggled under the weight of a massive debt load since oil prices crashed in 2014.
Weatherford recorded $2 billion in one-time expenses during the final quarter of 2018 which largely included write-offs.
Revenue from Weatherford’s Eastern Hemisphere markets fell 11 percent to $653 million in the fourth quarter ended Dec. 31 due to the sale of some of its land drilling rigs and lower revenue in the Middle East.
Its adjusted loss narrowed to $140 million or 14 cents per share, from $329 million or 33 cents per share a year earlier.
Analysts on average had expected a loss of 12 cents per share, according to IBES data from Refinitiv.
Revenue overall fell marginally to $1.4 billion from $1.5 billion.
Exxon Mobil Corp on Friday reported a quarterly profit that topped analysts’ estimates, pushing its shares up as oil and natural gas output rose slightly on a year-over-year basis.
The company’s fourth-quarter net income fell to $6 billion, or $1.41 a share, from $8.38 billion a year ago. But earnings excluding the impacts of tax reform and impairments rose to $6.4 billion from $3.73 billion a year ago.
Analysts had forecast a $1.08 a share profit excluding one-time items, according to data from Refinitiv.
Exxon’s oil equivalent production rose to just over 4 million barrels per day, up from 3.9 million bpd in the same period the year prior. The company said its output in the Permian Basin, the largest U.S. shale basin, rose 90 percent over a year ago.
Results for oil and gas production were “especially strong,” said Brian Youngberg, an analyst with Edward Jones. “It was a good quarter to end the year. I think the focus now will be on improving the cash flow,” he said.
Exxon is not planning share buybacks this quarter, though, which makes it the only international oil company “not currently repurchasing shares,” analysts with Simmons Energy said in a client note.
The company now expects to spend $30 billion this year, up from about $28 billion it had forecast previously, and analysts at J.P. Morgan said in a client note that the higher spending “takes away from the ‘sizzle’ of the quarter.”
CEO Darren Woods said Exxon would sanction liquefied natural gas (LNG) projects on the U.S. Gulf Coast and in Mozambique this year. Qatar Petroleum and Exxon are expected to announce plans next week to proceed with the $10 billion Golden Pass LNG Terminal export project in Texas.
Pretax earnings in its refining business were $2.7 billion, up $1.70 billion over the same period the year prior.
Exxon earned $1.1 billion more pretax in its upstream business than it did in the fourth quarter of 2017, and said higher natural gas prices were partially offset by lower liquids pricing.
Pretax profits in Exxon’s chemicals business were down $191 million on weaker margins, growth-related expenses and higher downtime and maintenance.
Woods credited better-than-expected results to the company optimizing its operations across the board, and said it has an advantage because of its ability to tie decisions in the oil field to logistics and refining.
“Irrespective of where we are in the cycle, we’re going to be advantaged versus the rest of industry,” he said. Woods joined a conference call with analysts this morning for the first time since becoming CEO two years ago.
Production declines have been a significant issue in previous quarters for Exxon and it is a “positive sign” that production improved in the fourth quarter, said Muhammed Ghulam, analyst with Raymond James. But he noted the earnings beat was “partially driven by one-time asset sale gains of more than $800 million” from a refinery sale.
https://www.reuters.com/article/us-exxon-mobil-results/exxon-mobil-profit-tops-estimates-as-production-rebounds-idUSKCN1PQ4SV
An onshore block is awarded by the State-owned Abu Dhabi National Oil Company (Adnoc) to Occidental Petroleum for US$244 million (Dh893 million) participating fee. The Onshore Block 3 in Abu Dhabi will be under the US firm’s 100% for exploration as part of a 35-year concession agreement.
Vicki Hollub, chief executive at Occidental Petroleum said that the block could hold as much as 3.5 billion barrels of oil and up to a trillion cubic feet (tcf) of gas.
“One thing that we’re excited about this Block Three in Abu Dhabi is that it’s one and half million acres, so it’s really huge. And in addition it has stack play,” added Hollub.
A stack play pertains to formations that have more than one reservoir atop each other.
“We believe that there’s potentially 3.5 billion barrels in place. We expect that it has a tcf of gas, so we have both the ability to find oil and the ability to find gas in this block,” she continued.
Adnoc chief executive and UAE State Minister, Dr Sultan Al Jaber said “Occidental was selected after a competitive bid round in which they presented a compelling plan for exploration of the area,”
“Occidental is already Adnoc’s joint venture partner in Shah onshore gas production and processing and the award reflects our strategy to develop long-term partnerships with those who want to invest with us across our value chain,” he added.
In 2011, a 30-year right was awarded to Occidental Petroleum to develop the US$10 billion Shah gas field in Abu Dhabi. The Houston-based firm holds 40% participating interest in the development of the ultra-sour gas. This facility which is adjacent to Block Three, produces 1 bcf of gas per day as well as refine 3.5 million tonnes of sulphur annually from the fuel.
After last year’s announcement about the discovery of deposits equivalent to a 1% increase to existing oil reserves and a 7.1%addition to proven gas reserves, Abu Dhabi needs expertise to develop sour gas resources.Sour gas contains high levels of sulphur which needs to be separated to produce cleaner gas for extraction.
“So now we have the capacity up to 1.3 bcf a day. Ultimately, we’re going to look at how the reservoir performs and what additional gas we may be able to get into that plant, but I believe over time we’d be able to expand that capacity even more,” Hollub said.
Las January, Offshore concessions were also awarded to a consortium of Italian energy firm ENI and Thailand’s PTT Exploration and Production Public Company.
http://www.eog-asia.com/adnoc-awards-onshore-concessions-to-us-energy-firm/
Anadarko Petroleum Corp. has announced that Mozambique LNG1 Co. Pte. Ltd – the jointly owned sales entity of the Mozambique Area 1 co-venturers – has signed an LNG sale and purchase agreement (SPA) with CNOOC Gas and Power Singapore Trading & Marketing Ltd.
According to the statement, the SPA is for 1.5 million tpy of LNG for a 13-year term.
Mitch Ingram, Anadarko Executive Vice President, International, Deepwater & Exploration, said: “We are pleased to announce this SPA with CNOOC, an important global energy player in one of the biggest and fastest growing LNG markets in the world.
“This deal gives China’s largest LNG importer access to Mozambique LNG’s world-class gas resources, which are strategically located off the East Coast of Africa, and will provide China with a clean source of energy for years to come.
“Mozambique LNG is extremely pleased to have CNOOC on board as one of our foundation customers.
“This agreement adds to our growing list of customers in the Asia Pacific region, demonstrating the excellent progress we are making toward our stated goal of taking a final investment decision during the first half of this year. We expect to announce further SPAs in the near future.”
The Anadarko-operated Mozambique LNG project will be the first onshore LNG development in Mozambique. It will initially consist of two LNG trains with a total nameplate capacity 12.88 million tpy to support the development of the Golfinho/Atum fields located entirely within Offshore Area 1.
https://www.lngindustry.com/liquefaction/04022019/anadarko-announces-lng-spa-with-cnooc/
China’s imports of liquefied natural gas (LNG) rose to another monthly record in January, even as the country grapples with high gas inventories amid a warmer-than-usual winter, according to shipping data and industry sources.
The world’s second-largest LNG importer took 6.55 million tonnes of LNG in January, beating the previous record hit in December by nearly 2 percent, according to Refinitiv Eikon shipping data.
China’s imports last year surged 41 percent from 2017 after gas shortages the previous winter prompted Chinese companies to stock up on supplies and pre-order cargoes, with Beijing continuing to push millions of households to switch to gas from coal for heating.
But the import growth is not wholly due to a rise in demand, said an industry source familiar with the Chinese market.
“When people see these numbers, they think Chinese demand is up ... but actually it is causing a headache (for importers) as (they) have overbought and can’t find demand to absorb the cargoes,” the source said, declining to be identified as he was not authorized to speak with media.
China National Offshore Oil Corp (CNOOC) resold at least one LNG cargo in January and possibly another, an unusual move during what is typically a peak demand period and highlighting this year’s warmer weather, industry sources said.
Chinese traders are offering LNG cargoes to international buyers or selling into their domestic market at lower-than-expected prices, the first source said.
The Lunar New Year holiday has also made the situation worse because factories are shutdown for a least a week, he said.
Wholesale LNG from small, land-based liquefaction plants fell to 3,500-3,950 yuan ($519-$586) a tonne on Feb. 2, less than half levels of last year, according to Chinese gas-price monitoring agency yeslng.com.
Quotes at receiving terminals in East China’s Shandong and North China’s Tianjin last stood at 4,500 yuan ($667) a tonne, down 17 percent and 5 percent, respectively, from late November, shortly after heating season started.
China’s gas demand growth should decelerate from the past two years, said James Taverner of energy consultancy IHS Markit.
“Coal-to-gas switching mandates are moderating due to ... security of supply concerns, and weakening economic growth,” Taverner said.
There is also limited capacity in North China for further LNG ramp-up after big increases the past two years, he said.
Lower-48 natural gas demand surged in 2018, managing to offset ballooning production volumes and putting the gas market on the razor’s edge going into this winter. Demand growth occurred across all domestic sectors as well as export markets, but was led by increased demand from power generators. Some of that was weather-related. However, there also was a level-shift up in demand on a per-degree basis, meaning more gas was burned than historically at the same temperatures, signaling a gain in gas market share. What were the drivers, and can we expect this growth pace to continue? Today, we take a closer look at the demand components behind the recent growth trends.
As we discussed recently in our Razor’s Edge Part 1 blog, the Lower-48 gas supply-demand balance in 2018 was especially tight. The combination of the tighter balance and an enormous deficit in storage compared with 2017 and the five-year average had the market unsettled going into the coldest months of this winter. At the time, we looked at the annual average balance for the January-November period in 2018 versus the prior years going back to 2010.
Figure 1 shows the same graph again, this time using the full-year average balance for each year (navy blue bars, left axis), which takes total supply minus total demand (including imports/exports but excluding storage), based on data from RBN’s daily NATGAS Billboard report. A positive balance reflects the surplus supply that is available for storage. A larger surplus on average leads to higher injections during the summer and/or lower withdrawals during the winter (a more bearish price scenario), while a smaller surplus or negative balance has the opposite effect, dampening injections and requiring stronger withdrawals to help balance the market (more bullish). The graph also overlays the November-ending storage inventory estimate for each year (orange line, right axis), as reported by the Energy Information Administration (EIA), which reflects how much gas was available for withdrawal going into the highest-demand winter months.
Figure 1. Lower-48 Annual Average Supply-Demand Balance. Source: NATGAS Billboard
As the 2016, 2017 and 2018 bars indicate, the market has carried a negative balance for three years straight. In 2018, the balance averaged negative-0.75 Bcf/d, slightly tighter than the negative-0.67 Bcf/d in 2017, but not quite as tight as the ~1-Bcf/d deficit in 2016 or the negative-1.5 Bcf/d back in 2013. Nevertheless, when coupled with the overall lower storage levels — less than 3,000 Bcf at the end of November 2018 (the orange marker on the bottom right) compared with about 3,700 Bcf in the same week in 2017, almost 4,000 Bcf in 2016 and 3,600 in 2013 — the 2018 gas market was the most bullish market of this decade. (While 2013 ended with a large negative supply-demand balance and the extreme polar vortex winter of 2013-14 depleted storage further, leaving a year-on-year deficit that lingered through much of 2014, the overall supply-demand balance in 2014 was positive, which helped keep the inventory above 3,400 Bcf going into winter 2014-15.)
It’s not that supply was lower. In fact, Lower-48 dry gas production rose more than 8 Bcf/d last year, marking the biggest one-year gain in the past eight years. (It grew by an average 2 Bcf/d each year from 2011 through 2018, even including an annual average drop of about 1.5 Bcf/d in 2016 before crude oil prices recovered. The second biggest year-on-year gain — of about 4.6 Bcf/d — was in 2014.) That meant total supply rose more than 8 Bcf/d as well, given that imports from Canada and LNG slipped only slightly. But, as we laid out in the Razor’s Edge series, demand as a whole grew slightly more than supply — 8.2 Bcf/d of incremental demand in 2018, compared with 8.1 Bcf/d of incremental supply, to be exact. About 20% of that increased demand (1.5 Bcf/d) came from exports — feedgas deliveries for LNG exports grew by 1.1 Bcf/d to an average 3.1 Bcf/d in 2018, and the U.S. piped about 0.4 Bcf/d more gas to Mexico. That means that 80% of the demand growth came from incremental domestic consumption. Consider Figure 2, which plots total Lower-48 gas consumption from the power generation, residential/commercial (res/comm) and industrial sectors combined for 2018 (red line) versus 2017 (purple line). The previous three years are also shown in the background as dashed lines going back to 2014, but they are largely clustered near the 2017 line. In contrast, the 2018 red line clearly stands apart, and what sticks out to us is this: not only did demand level-shift up in 2018, it did so throughout almost the entire year, as indicated by the green arrows.
Figure 2. Lower-48 Natural Gas Consumption. Source: NATGAS Billboard
All in all, domestic consumption jumped 6.9 Bcf/d year-on-year, to an average 81 Bcf/d in 2018, up from 74.1 Bcf/d in 2017. If we break out demand by sector — as shown in Figure 3 — we can see that gas consumption rose in all three sectors in 2018 (again, shown by the red line). Of the nearly 7 Bcf/d of incremental demand, more than half (3.8 Bcf/d) came from the power sector (left graph in Figure 3), while res/comm demand (middle graph) contributed another 2.4 Bcf/d and the remaining 0.7 Bcf/d stemmed from the industrial sector (right graph).
Figure 3. Domestic Consumption by Sector. Source: NATGAS Billboard
Some of the demand growth can be attributed to weather — temperatures in the first and fourth quarters of 2018 (the winter months) were generally lower than in the same periods in 2017, boosting res/comm usage for heating. And then, temperatures were higher year-on-year from May through September in 2018, lifting gas-fired power generation demand for cooling during the warmer months.
But there’s more to it than that. Consumption was also stronger on a temperature-adjusted basis, meaning if the weather had been exactly the same in 2018 versus 2017, the demand in 2018 still would've been higher. This point is illustrated in Figure 4, which plots the difference between actualized demand and modeled demand (gray bars). The modeled demand is what we would expect for a given day based on the forecasted temperatures and a regression analysis of where demand has been historically (looking back three or more years) at the same temperatures and on those same days. A negative value indicates actual demand came in weaker than the modeled expectation at the same temperatures, and a positive value indicates the opposite — that actual demand came in stronger than expected at the same temps.
Figure 4. Actual vs. Modeled Gas Demand. Sources: IAF Advisors, RBN
As the increasingly positive values on the right side of the graph suggest, demand through 2018 peeled away from the historical norm (to the upside), averaging about 5 Bcf/d higher than the model estimates for the same temperatures. This type of increase points to structural changes in the demand sectors. In the power sector, gas-fired generation capacity additions, as well as coal and nuclear plant retirements, led to increased utilization of new and existing gas-fired plants. Industrial gas consumption also got a boost with the addition of petrochemical steam crackers that use gas as a feedstock.
Gas demand growth, both from exports and the domestic sectors, was a game-changer in 2018. The question now is, can we expect a repeat performance in 2019? Certainly, the liquefaction, gas-fired generation and industrial plant capacity that was added in 2018 is here to stay, and there are more LNG export facilities, coal plant retirements and gas plant additions on the way this year. But weather will continue to play a large part in that, as will commodity prices and fuel competition, particularly with renewables now increasingly part of the mix. As we noted in Lean On Me, solar and wind — the two renewable-energy sources whose development and use have been rising exponentially the past few years — produce power efficiently and without any fuel costs, but only intermittently (when the sun shines and the wind blows), and that modern gas-fired power plants are the most flexible and responsive in terms of stepping in to fill the gaps. At the same time, the structural shifts in demand are increasingly dependent on regional temperatures. A super-hot summer in Texas with relatively low wind speeds (and less wind-farm generation) could result in temperature-adjusted growth in gas demand that meets or exceeds 2018 levels. Conversely, a relatively mild, windy summer may lead to significantly slower growth. (See Runnin’ Against the Wind and You’ve Got the Power for more on wind generation in Texas). As production also continues to grow, it will take more extreme weather to materialize at the right time of year and in the right region to have an impact on the balance. Overall, though, economic indicators and structural changes to the power generation fleet point to sector demand remaining strong. It’s a theme we’ll be examining further in future blogs.
https://rbnenergy.com/razors-edge-part3-structural-shifts-propel-lower-48-gas-demand
British chemical manufacturer Ineos has called on the UK government to change its ‘unworkable’ rules on gas fracking which it says could force the closure of the industry.
Ineos has the largest shale gas license acreage in Britain and wants to develop the sites to cut its reliance on imported gas, which it says will dramatically reduce its costs.
“The Government is shutting down shale by the backdoor and is betting the future of our manufacturing industry on windmills and imported gas,” Ineos said in a statement on its website.
Ineos said Britain must change its so-called traffic light seismicity regulations which mean fracking must be halted for 18 hours if seismic activity of magnitude 0.5 or above is detected at sites.
“Ineos calls upon the Government to either make shale workable or shut it down,” Ineos said.
Cuadrilla, currently the only company to have fracked for gas in Britain, had to halt operations several times last year at its Preston New Road site in northwest England due to seismic events which exceeded the limit.
It has also said the current regulations are too stringent and experts agree that the limit for tremors could be safely raised at fracking sites.
However, the government, which initially supported fracking to cut Britain’s reliance on imports as North Sea gas supplies dry up, said earlier this year it has no plans to change the rules.
Britain currently imports around 60 percent of its gas needs via pipelines from Norway and continental Europe and tankers of liquefied natural gas (LNG) from countries including Qatar, Russia and the U.S..
Fracking, or hydraulically fracturing, involves extracting gas from rocks by breaking them up with water and chemicals at high pressure.
It is fiercely opposed by environmentalists who have raised concerns about potential groundwater contamination and say extracting more fossil fuel is at odds with Britain’s commitment to reduce greenhouse gas emissions.
The U.S. energy secretary, his Qatari counterpart and representatives of Exxon Mobil and the Golden Pass liquefied natural gas facility will announce a Qatari investment in the United States on Tuesday, the Department of Energy said on Monday.
No other details were immediately available. But Reuters reported on Feb. 1 that Qatar Petroleum and Exxon Mobil were expected to announce plans this week to proceed with a $10 billion project expanding the Golden Pass export facility in Texas.
ConocoPhillips, the third partner in the existing LNG export terminal, plans to sell its 12.4 percent stake and does not plan to participate in the expansion, Reuters reported, citing three people familiar with the transaction.
Golden Pass LNG started as a receiving and regasification facility in Sabine Pass, Texas able to handle up to 2 billion cubic feet of natural gas imports per day. But as U.S. gas production has soared, the demand for export capacity has risen.
The facility expansion is part of Qatar Petroleum’s plans to invest about $20 billion in the United States as the firm seeks to increase its overseas oil and gas footprint.
BP’s profit doubled to $12.7 billion in 2018, driven by strong growth in oil and gas output following the acquisition of a large portfolio of U.S. shale assets.
The company’s debt rose however, and the pace of its share buyback scheme slowed in the last quarter as it completed the $10.5 billion BHP acquisition.
“We now have a powerful track record of safe and reliable performance, efficient execution and capital discipline. And we’re doing this while growing the business,” BP Chief Executive Officer Bob Dudley said in a statement.
Rivals Royal Dutch Shell, Exxon Mobil and Chevron all reported stronger-than-forecast earnings last week driven by higher production in U.S. shale basins where Oil Majors have invested billions in recent years.
BP, like its competitors, wrapped up 2018 on a strong note despite a sharp drop in crude prices at the end of the year that wiped out most gains made in share prices throughout the year.
Uncertainty over the outlook for oil prices as well as concerns over global economic growth and sino-American trade tensions also continued to weigh on the sector.
After settling the vast majority of payments for the deadly 2010 Deepwater Horizon spill in the Gulf of Mexico, totaling nearly $70 billion, BP has more recently focused on growing production into the next decade, including the BHP deal which is its largest in 30 years.
Fourth-quarter underlying replacement cost profit, the company’s definition of net income, reached $3.5 billion, exceeding a company-provided forecast of $2.63 billion.
That compared with a profit of $2.11 billion a year earlier
and $3.84 billion in the third quarter of 2018.
For the year, BP’s profit rose to $12.7 billion, double the previous year’s $6.17 billion. Analysts expected 2018 profits of $11.88 billion.
BP’s production rose in 2018 to 3.7 million barrels of oil equivalent per day after it completed the acquisition of BHP’s onshore U.S. shale portfolio and thanks to the start up of new fields including the 120,000 barrel per day Clair Ridge project in the North Sea.
Excluding its share of production from its 20 percent stake in Russia’s Rosneft, BP’s production was up 8.2 percent from 2017.
Gearing, the ratio between debt and BP’s market value, rose to 30.35 percent at the end of 2018 from 27.4 percent a year earlier. Net debt was $44.1 billion at the end of last year.
Cashflow for 2018 reached $26.1 billion, including a $2.6 billion gain due to inventory sales, compared with $24.1 billion for 2017.
https://uk.reuters.com/article/us-bp-results/bps-2018-profit-doubles-as-output-soars-idUKKCN1PU0IU
Murphy Oil Corporation plans to grow its upstream production by ~20% this year versus 2018 levels.
Sharp increases in its Eagle Ford development activity combined with its new Gulf of Mexico JV are Murphy Oil's two primary growth generators.
Better debt coverage a product of rising cash flow generation.
Midsized oil & gas player Murphy Oil Corporation (NYSE:MUR) reported earnings last week that provided the market with a much better picture of how management plans to navigate volatile oil markets this year. As things stand today, Murphy Oil Corporation increased its 2019 capital expenditure budget in order to boost its upstream production by 20% on an annual basis. That program includes ramping up development of its unconventional Eagle Ford position as short-cycle investment opportunities offer near-term growth catalysts. Let’s dig in.
Better debt coverage
Murphy Oil grew its adjusted EBITDA by 28% year over year to $1.6 billion in 2018. As the firm exited 2018 with $3.2 billion in debt on the books, its total debt to adjusted EBITDA ratio came in at 2.1x last year. In 2017, Murphy Oil posted $1.2 billion in adjusted EBITDA and ended the year with $2.9 billion in debt, giving it a total debt to adjusted EBITDA ratio of 2.4x during that period. Adjusting the EBITDA of a firm, as long as those adjustments are truly for special one-item items, removes the noise from that cash flow figure.
Total debt to adjusted EBITDA is a useful metric as it showcases how well a firm is managing its ability to eventually pay off those liabilities. If the size of a firm’s debt load vastly exceeds its cash flow, then that is cause for concern.
On the flip side, if a firm’s total debt to adjusted EBITDA ratio is steadily moving lower, that is a sign the company is getting a much better handle on its liabilities. Some firms prefer to use net debt to adjusted EBITDA, which is a valuable metric if that cash is going to be used to pay off debt or the firm has a tendency to always keep a sizable amount of cash on the books. However, if that cash has already been or will soon be pledged to other activities, then using the net debt figure improperly distorts this metric.
https://seekingalpha.com/article/4237773-murphy-oil-targets-significant-production-growth-year
South African giant Gold Fields is the latest miner in Australia to turn to renewable energy, at its Granny Smith gold mine near Laverton, giving the green tick to a hybrid solar-gas power plant described as one of the world’s largest renewable energy microgrids.
Up to 30 people will be on site at the peak of construction, which will see 20,000 solar panels installed to complement Granny Smith’s existing gas-fired power station.
The 8MW solar installation will be backed up by a 2MW/1MWh battery system and reduce the mine’s fuel consumption by up to 13 per cent, the equivalent of taking 2000 cars off the road.
Construction at Granny Smith, about 20km south of Laverton, is expected to start in May, with the microgrid to be up and running by the December quarter.
The installation is the latest move in the gold producer’s shift to clean up its energy supply after dumping diesel when Aggreko installed its gas-fired plant in 2016 following the construction of the Eastern Goldfields Pipeline.
It will expand Aggreko’s power-generating capacity at Granny Smith to 24.2MW, with the 1100m-deep Wallaby underground deposit and its power requirements continuing to grow.
A desire to shift to more sustainable power was behind the decision to approve the project, but Gold Fields Australasia executive vice-president Stuart Mathews also sees potential cost savings from the transition to renewable energy.
“As we stand today we have a minimum of eight years (at Granny Smith) and still have no end in sight as long as we invest in exploration in the mine, so it has long life and that’s why we have confidence to commit to something like this,” he said.
“As we get deeper we have to invest in getting more power down that mine.
“We had an opportunity to go a bit new age by using solar, which is even a further reduction in the cost of energy for the site, and power is one of our biggest costs on a mine site.”
About half of the power supply at Granny Smith is required for the Wallaby mine, while the other half will be used to run its 3.2 million tonne a year processing plant and camp.
Gold Fields has followed ASX-listed miners Sandfire Resources and Independence Group in the transition to renewable energy.
Sandfire commissioned a 10.6MW solar panel installation at its DeGrussa copper-gold mine in the Mid West in 2016.
A solar addition to the diesel-fired power plant at Independence Group’s Nova nickel mine in the Goldfields has also been announced.
https://thewest.com.au/news/kalgoorlie-miner/green-push-for-granny-smith-ng-b881093633z
Oil and Gas Exploration Economics to Improve
file photo
By MarEx 2019-02-04 20:04:56
After a difficult few years, the oil and gas exploration sector is back in the black – and keen to stay there, according to new analysis from Wood Mackenzie.
Dr. Andrew Latham, vice president, Global exploration, said: “We are seeing a long-overdue recovery in the sector. Last year conventional exploration returns hit 13 percent - the highest calculated in more than a decade. As 2018’s discoveries are appraised and projects move through the development cycle, we expect these economics to improve further.”
In 2018, exploration added at least 10.5 billion barrels of oil equivalent (boe) in conventional new field volumes. This was split 40:60 oil to gas. Last year saw three play-opening discoveries – Ranger and Hammerhead on Guyana’s prolific Starbroek Block and the Dorado find, which confirms a new liquids play in the Roebuck sub-basin, offshore Australia.
Last year also saw three giant finds – Novatek’s 11.3 trillion cubic feet North Obskoye gas find offshore Russia, the Calypso gas discovery, offshore Cyprus, and Guyana’s Hammerhead. This trio, together with the 18 large discoveries made last year, account for 80 percent of the total discovered resources.
Latham says: “The Americas will receive a lot of attention this year. Latin American plays account for one third of global large and giant prospects scheduled for drilling in 2019. This region will also see one-third of the potential play-opening wells. Exceptional reservoirs in Brazil, Guyana and Mexico will attract the most investment. We expect billion-barrel scale volumes from these emerging and newly-proven plays, as has been the case in the last couple of years.”
Southern and western Africa will also see a resurgence in offshore exploration, and worldwide, 2019 discoveries are expected to add around 15 billion-20 billion boe of new resource. This could come from discoveries such as Peroba, a giant pre-salt prospect in Brazil’s Santos basin, estimated to hold in-place volumes of more than five billion boe. Peroba lies on trend with the giant Lula discovery. If the well is successful, partners Petrobras, BP and CNODC are likely to be sitting on a very significant find.
Additionally, Brulpadda-1 in South Africa’s frontier Outeniqua basin has estimated volumes of around one billion boe. Nour-1 in Egypt’s prolific Nile Delta has estimated volumes of around 860 million boe.
Kingsholm-1 in the U.S. Gulf of Mexico’s prolific Mississippi Canyon area has estimated volumes of around 300 million boe, and the Jethro prospect on the Orinduik Block offshore Guyana, has estimated volumes of around 200 million boe in the same play as the recent Hammerhead find.
Latham notes that fewer companies are drilling fewer wells, and many companies, regardless of size, have cut their exploration spend. “We expect companies will focus on their best prospects, with global exploration and appraisal spending for 2019 staying close to its 2018 level of just under $40 billion per year.”
https://www.maritime-executive.com/article/oil-and-gas-exploration-economics-to-improve
Welcome to The GERM Report by Dan Graeber, a commentary on the intersection between geopolitical events and the price of oil. GERM stands for Geopolitical Energy and Risk Monitoring. Our indicator is based on the expected price volatility by the end of the current trading week.
Risk level: Orange
RED: Severe (+/- 4%) ORANGE: High (+/- 2%) YELLOW: Elevated (+/- 1%) BLUE: Guarded (+/- ½%)
THE BOOSTER SHOT
If power fades with distance, the tea leaves on Trump become interesting.
There are only a few viable sources for heavy crude for the US.
Knowing when to balance and when to bandwagon is key to peace.
The world-wide responses to the situation unfolding in Venezuela and the collapse of the Intermediate-Range Nuclear Forces treaty signal shifting polarity in the international system. Breaking the binds of interdependence through isolation, the Trump administration may be encouraging balancing behavior at best, and a security dilemma at worst. For oil, US sanctions against Venezuela may be something of a self-imposed embargo on the heavier crudes that Gulf Coast refiners desire. For those in the game of statecraft, policy that is out of step with the international order often has dire consequences.
The US Treasury Department last week hit Venezuela and state-run PdVSA with economic sanctions. Gary Simmons, a senior vice president at Valero, said the refiner was no longer taking “anything” from Venezuela, which supplied about 20 percent of the heavy oil running through its US refinery system. Figures from ClipperData, however, expose the extent of the vulnerability. US imports of Venezuela in January averaged 510,000 bpd, up 20 percent from January 2018. Canada, another main supplier of heavy crude, is just emerging from self-imposed restrictions in Alberta while, at 657,000 bpd, Saudi exports are at an eleven-month low, and down 5 percent from January 2018.
With the shortage, the price for Brent crude oil jumped nearly 5 percent on the week, closing the trading day Friday at $62.84 per barrel.
Last week’s GERM analysis pondered the fate of the Monroe Doctrine, starting with the Cuban Missile Crisis and ending with Russian oil company Rosneft’s 49.9 percent control over PdVSA subsidiary, and US-based refiner, Citgo. And “witch hunt” or not, the Mueller investigation into Russian meddling in US politics shows Moscow is hell bent on returning to the height of its former Soviet status.
One of the basic tenets of international relations is that "neighbors of neighbors are friends” and US support for Guaido may emblematic of that because of the necessity to create a friendly Venezuela. But trade policy with US neighbors Canada and Mexico brings regional friendship into question. Internationally, leaving the INF treaty gives the United States the freedom necessary to build up the military arsenal necessary to challenge China and Russia, but it also encourages the latter two powers to form an alliance to balance against the United States. Defensive actions by one state can sometimes result in offensive reactions.
The ability to project power diminishes with distance, which may help explain why the Trump administration is withdrawing from Afghanistan and Syria while at the same time mentioning a military option for Venezuela. This in turn means China and Russia will protect their interests in Venezuela while seizing the opportunity in Central Asia and the Middle East. Considering Moscow’s historic aspirations in the region, Turkish support for Maduro shows Russia knows how to play its hand.
Writing in the journal International Security, Stephen M. Walt of the realist school wrote that states either balance -- ally in opposition to the biggest threat -- or bandwagon -- ally with the biggest threat. China, arguably the No. 2 in the international arena behind the United States, is exhibiting balancing behavior by lining up with a weaker Russia rather than hopping on the US bandwagon. This strategy was pursued by Henry Kissinger when he advocated détente with China, preferring to ally with the weaker side in a trio of leading powers. A supporter of détente in his own right, Zbigniew Brzezinski in one of his last scholarly articles wrote that a US pullout form the Muslim world would generate a “crisis of confidence” in America as stabilizer.
“In different but dramatically unpredictable ways, Russia and China could be the geopolitical beneficiaries of such a development even as global order itself becomes the more immediate geopolitical casualty,” he wrote in The American Interest.
Meanwhile, Walt argued that following balancing policies in a bandwagoning world leaves allies discouraged by the complacent view of threats.
“Conversely, following the bandwagoning prescription (employing power and threats frequently) in a world of balancers will merely lead others to oppose you more and more vigorously,” he wrote.
More often than not, he said, it is a world of balancers.
Venezuela may be the running theme in the market this week, especially if European nations enact their own set of sanctions. In terms of data, things are pretty light outside the typical look at US inventory levels mid-week. There are a handful of speaking events for banking chiefs, including Dallas Fed President Robert Kaplan on Thursday. Expect the bulls to run this week for crude oil in the Orange range, moving at least 2 percent.
A subsidiary of Houston oil company Noble Energy purchased stakes in a pair of pipelines to move crude oil and natural gas liquids from the Permian Basin to the Port of Corpus Christi.
Houston pipeline and storage terminal operator Noble Midstream Partners reported buying a 30 percent stake in the EPIC Crude Oil Pipeline and a 15 percent stake in the EPIC Y-Grade Pipeline.
In a statement released Monday morning, Noble Midstream said the company anticipates investing between $330 million and $350 million in cash for its stake of the crude oil pipeline and another $165 million to $180 million for its stake of the EPIC Y-Grade Pipeline.
"We are excited to work with our new partners and participate in the EPIC projects, capitalizing on the growing demand for crude oil and NGL takeaway and export capability from the Permian Basin," Noble Midstream CEO Terry Gerhart said in a statement. "These additions are complementary to our existing portfolio, enhance our customer diversification, and will add a stable and high-quality source of cash flow from a premier U.S. unconventional basin."
The two Permian Basin-to-Corpus Christi projects are being developed by San Antonio pipeline operator EPIC Midstream Holdings LP.
The EPIC Y-Grade Pipeline is a 700-mile pipeline to move natural gas liquids, or NGLs, from the Permian Basin of New Mexico and West Texas to a facility in Robstown.
The EPIC Crude Oil Pipeline is a 650-mile project to move crude oil and from seven terminals in the Permian Basin and Eagle Ford Shale of South Texas to a facility in Robstown.
As part of a plan announced in October, EPIC plans to temporarily use its natural gas liquids pipeline to ship crude oil starting in the third quarter.
Construction of the crude oil pipeline is expected to be complete by January 2020.
Los Angeles private equity firm Ares Management is backing both the natural gas liquids and crude oil pipelines.
"The strategic value of these projects to our shippers is clear through the exercising of the options by our partners," EPIC Midstream Holdings CEO Phillip Mezey said in a statement. "Both projects remain on schedule and are critical to the continued development of the Permian Basin and Eagle Ford Shale."
Tokyo Gas and Centrica have signed agreements to buy gas from Anadarko-operated Mozambique LNG project firming up the non-binding heads of agreements signed in June 2018. In a separate statement on Tuesday, Anadarko said it had signed a similar deal with Shell.
Tokyo Gas and Centrica have agreed to will jointly purchase 2.6 million tonnes per year, delivered ex-ship from Mozambique LNG from the start-up of production until the early 2040s.
This agreement provides the project with key foundation customers which will support the final investment decision by the Mozambique Area 1 joint venture partners, targeted for the first half of 2019, Centrica said on Tuesday.
“This innovative joint procurement approach takes full advantage of Mozambique’s central location between Europe and Asia, assisting both companies to access diverse markets and proactively manage demand fluctuations across regions with different market dynamics,” Centrica added.
Anadarko-operates the Mozambique LNG project which will be Mozambique’s first onshore LNG development. Fed by gas from the Golfinho/Atum fields located within Offshore Area 1, the project will initially consist of two LNG trains with the total nameplate capacity of 12.88 MTPA.
The Golfinho/Atum Project will also supply initial volumes of approximately 100 million cubic feet of natural gas per day (MMcf/d) (50 MMcf/d per train) for domestic use in Mozambique.
Takashi Uchida, Tokyo Gas’s President, and CEO said: “We are very happy that our commitment as foundation customers will contribute to the positive final investment decision of Mozambique LNG targeting the first half of this year. This first-ever joint procurement between Tokyo Gas and Centrica is supported by the long-term mutual relationship to strive for flexible and innovative LNG transactions between the European and Asian markets.
“This joint procurement represents the significant progress we are making towards securing the most competitive LNG. This year marks the 50th anniversary of when Tokyo Gas received Japan’s first LNG cargo from Alaska in 1969. Tokyo Gas Group will continue to provide safe, reliable and clean energy for our customers through the continued challenges to secure competitive LNG.”
Commenting on the SPA, Iain Conn, Centrica’s Group Chief Executive said: “We are delighted to conclude this co-purchase agreement with Tokyo Gas which secures our place as long-term foundation buyers for the Mozambique LNG project. The deal deepens our strategic partnership with Tokyo Gas and provides a flexible LNG supply source able to serve the needs of our combined customer base. With strong energy marketing and trading capabilities we are ideally placed to work with Mozambique LNG and this agreement will complement our existing positions as we continue to develop this valuable growth area of our business.”
Shell buys 2 MTPA
In a separate statement Tuesday, Anadarko said it signed a Sale and Purchase Agreement (SPA) with Shell International Trading Middle East Ltd. (Shell). The SPA is for 2 million tonnes of LNG per annum (MTPA) for a term of 13 years.
Mitch Ingram, Anadarko Executive Vice President, International, Deepwater & Exploration said: “We are very pleased to announce this SPA with Shell, which builds upon previously announced deals and takes our total long-term sales to more than 7.5 MTPA, with additional deals expected in the near future.”
“With demand for LNG expected to grow worldwide in the middle of the next decade, Shell’s strong global reputation in LNG, combined with Mozambique LNG’s significant resource and favorable geographic location, create a unique opportunity to provide customers with a long-term, reliable supply of clean energy.
“Mozambique LNG is extremely pleased to have Shell onboard as a foundation customer, and the Shell deal adds to our growing list of high-quality customers demonstrating the excellent progress we are making toward our stated goal of taking a final investment decision during the first half of this year. We are confident that through this deal, LNG from Mozambique will find its way to a diverse number of markets across the globe.”
Today’s gas sales and purchase agreements come just days after Anadarko last Friday announced the signing of a gas sale and purchase agreement (SPA) with CNOOC Gas and Power Singapore Trading & Marketing Pte. Ltd. (CNOOC), for gas to be produced from its gas field offshore Mozambique. The SPA is for 1.5 million tonnes per annum (MTPA) for a term of 13 years.
https://www.offshoreenergytoday.com/tokyo-gas-centrica-shell-pen-mozambique-gas-deals-with-anadarko/
Canadian LNG project developer Pieridae Energy has ratified benefits agreement negotiated with the Assembly of Nova Scotia Mi’kmaq Chiefs.
This benefits agreement establishes the framework under which the Mi’kmaq of Nova Scotia will benefit economically from the development, construction and operation of the Goldboro LNG project.
A Memorandum of Understanding (MOU) signed in 2013 originally outlined the relationship between Pieridae and the Mi’kmaq in Nova Scotia and this new benefits agreement underscores Pieridae’s commitment to ongoing engagement and relationship building with the First Nations communities in Nova Scotia, Pieridae Energy said.
Goldboro is the only LNG project on Canada’s east coast that has both permits for its current stage of development and an offtake customer, Uniper.
It is expected to produce about 10 million tonnes of LNG per year and have an on-site storage capacity of 690,000 cubic meters of LNG.
WPX Energy is updating its full-year guidance following commodity price changes that occurred after the company released initial 2019 guidance nearly three months ago.
The updated 2019 plan is focused on disciplined growth within cash flows based on $50 oil (WTI). Highlights include:
Estimating revised production of 149 – 161 MBoe/d (63% oil) in 2019. The midpoint implies greater oil production of more than 20 percent year-over-year.
Maintaining momentum into 2020 with 5-10 percent production growth from fourth-quarter 2018 to fourth-quarter 2019 based on a revised eight-rig program.
Reducing capital spending from a prior midpoint estimate of $1,550 million to $1,100-$1,275 million (excluding equity investments and land).
Forecasting only a 6 percent impact to original production guidance despite a 23 percent capital reduction of more than $350 million.
Releasing two rigs in the first quarter to average five rigs in the Permian and three in the Williston for the balance of 2019.
“We’ve worked hard over the past few years to position the company to spend within cash flows in a $50 world and still deliver nice growth,” said Rick Muncrief, chairman and chief executive officer.
https://boereport.com/2019/02/04/wpx-energy-reduces-2019-capital-plan/
Back in September, GDM Pipelines broke ground by becoming the first company to deliver on-demand risk assessments for every pipeline in Western Canada. Now, to expand on that enormous success, we are pleased to announce enhancements for users to visualize pipeline risk directly in the map.
Every pipeline is color coded green, yellow, orange or red according to its risk score, so you can easily identify your highest priority pipelines. You can choose to view pipelines by their Overall Risk, Consequence or Likelihood scores.
Additional layers for high consequence areas such as Population Density, Protected Areas, Land Use and Aboriginal Lands have also been added to provide context to the associated risk profiles. And, you can drill down to each individual pipeline to get a detailed view of the factors that contribute to its risk score.
With risk profiles available for every pipeline, you can not only understand the risk associated with your operating assets, you also gain insight into the long-term liability for your overall oil and gas infrastructure.
Pipeline Consequence with Population Density Layer in the background
Never has it been so easy to identify, view and manage the risk associated to your assets.
https://boereport.com/2019/02/05/a-new-perspective-on-pipeline-risk-and-liability/
Oil and gas operating costs in the U.S. shale basins have come down recently following a drop in crude prices, BP’s head of upstream Bernard Looney said on Tuesday.
Costs of drilling, labour and materials such as sand in shale fields rose last year amid a surge in output, particularly in the prolific Permian oil basin straddling Texas and New Mexico.
But a near 40 percent drop in crude prices in the last quarter of 2018 have helped reverse the rise in service costs, Looney said.
“We’re not seeing inflation around the world and in fact, even in the Lower 48, we are now beginning to see deflation again as prices have come back down,” Looney said in a analyst call after BP reported a doubling of profits in 2018.
BP became a major shale oil and gas producer following the acquisition of BHP’s onshore U.S. portfolio, known as the Lower 48. Its production rose to 349,000 barrels of oil equivalent per day (boed) in 2018 from 297,000 boed the previous year.
BP’s global production costs dropped by 45 percent from around $13.10 per barrel in 2013 to $7.24 last year, Looney said.
Russian oil producer Rosneft said on Tuesday its net profit fell to 109 billion roubles ($1.66 billion) in the fourth quarter, down 23.2 percent quarter on quarter.
Revenue in the last three months of 2018 stood fell 5.3 percent quarter on quarter to 2.2 trillion roubles, it said.
Rosneft’s EBITDA fell 24.1 percent to 488 billion roubles.
https://af.reuters.com/article/commoditiesNews/idAFR4N1ZV009
Rosneft said Tuesday it more than doubled its net income last year, taking advantage of the climbing price of crude despite an unstable market.
The state-controlled company reported a net income of 549 billion rubles ($8.4 billion, 7.3 billion euros) in 2018, up from 222 billion rubles the previous year. Revenues increased by 37 percent year on year to 8.2 trillion rubles.
Rosneft cited "favourable world price dynamics," caused in part by capping of output agreed with OPEC cartel countries, as well as improved company efficiency among the reasons for its increased revenue.
https://www.france24.com/en/20190205-russian-oil-giant-rosneft-doubled-net-income-2018
Venezuela's PDVSA debt to Russia's Rosneft down to $2.3 billion in fourth quarter
Venezuelan state oil company PDVSA’s principal amount of debt to Russian oil producer Rosneft stood at $2.3 billion at the end of the fourth quarter, down from $3.1 billion at the end of the previous three months, Rosneft said on Tuesday.
The oil producer said its outlook for crude oil and gas condensate production in 2019 implied growth of between 3 and 4.5 percent from 2018 levels, depending on the implementation of a global oil output deal in the first half of the year.
Roughly 20 percent of the hydraulic fracturing fleets that were active in mid-2018 have now been idled or are being idled, as lower oil prices prompt producers to tighten their budgets, Liberty Oilfield Services Inc estimated on Tuesday.
The company in its fourth-quarter earnings said a number of customers made last-minute decisions to defer well completions, in part because of a drop in oil prices at the end of last year.
U.S. oil prices fell by almost 40 percent in the fourth quarter of last year amid concerns of growing supply and slowing economic growth. The steep decline has negatively impacted many oilfield service companies that are still working to recover from the 2014 price crash.
Liberty said its customers are still finalizing budgets for 2019 and that it expected more clarity on 2019 completions demand by the end of the first quarter.
The company reported a fourth-quarter profit of 27 cents per share, missing analysts’ estimates of 31 cents per share, according to Refinitiv IBES data. Fourth-quarter revenues of $473 million also missed consensus estimates of $496.9 million.
Oil and gas producer Anadarko Petroleum Corp on Tuesday reported a fourth-quarter profit that missed analysts’ estimates by a wide margin, as it spent more on its projects in West Texas and northeast Colorado.
Oil producers, betting on a recovery in oil prices since their slump in 2014, have ramped up production in the U.S. shale basins, and the country overtook Russia and Saudi Arabia to become the world’s biggest crude producer with daily output approaching 12 million barrels.
However, fears of a glut in the oil market sent prices down roughly 40 percent in the three months ended Dec. 31.
Anadarko’s sales volume of oil, natural gas and natural gas liquids averaged about 701,000 barrels of oil equivalent per day (boe/d), up from 637,000 boe/d a year earlier.
However, the rise in sales volume was offset by a 19 percent jump in expenses as the company ramped up investments in the Delaware basin of West Texas and DJ basin of northeast Colorado.
The oil and gas producer said adjusted net income rose to $184 million, or 38 cents per share, in the three months ended Dec. 31 from $106 million, or 18 cents per share, a year earlier.
Analysts on average had expected the company to post a profit of 60 cents per share, according to IBES data from Refinitiv.
In the year-earlier quarter, the company had recorded an income-tax benefit of $1.11 billion, largely due to U.S. tax reforms.
Suncor Energy Inc, Canada’s second-largest energy producer, reported a quarterly loss on Tuesday compared with a profit a year ago, as lower prices for the country’s crude offset gains from higher refinery margins.
Canada, the world’s fourth largest producer of crude oil, has suffered from a steep discount for its oil, as tight pipeline space and insufficient rail capacity pushed the differentials between Canadian oil and U.S. prices to their largest spread in years.
Suncor produced 432,700 barrels per day from the oil sands operations in the fourth quarter, compared with 446,800 a year earlier. Cash operating costs per barrel for oil sands operations rose to C$24.50 a barrel, up from C$24.20 a barrel a year ago. The Calgary, Alberta-based company reported a net loss of C$280 million, or 18 Canadian cents per share, in the fourth quarter ended Dec. 31, from a profit of C$1.38 billion, or 84 Canadian cents per share, a year earlier.
The fourth quarter included a $637 million foreign exchange loss on the revaluation of U.S. dollar-denominated debt, as well as a non‑cash impairment loss on an equity investment.
Total upstream production rose to 831,000 barrels of oil equivalent per day, compared with 736,400 in the year-ago quarter.
Earlier on Tuesday, Suncor announced its quarterly dividend was increased by 17 percent to 42 Canadian cents per common share, payable March 25.
Norwegian oil company Aker BP posted a smaller-than-expected increase in fourth-quarter earnings due to higher production costs and lower oil prices, but raised its dividend.
The company said on Wednesday earnings before interest and taxes rose to $403 million (£311.2 million) from $305 million (£235.5 million) in the same quarter a year earlier, lagging the $491 million expected by analysts in a Reuters poll.
The Oslo-listed firm’s shares opened down 2 percent, lagging a 0.5 percent fall in the European oil and gas index.
“Revenues were impacted by low oil prices at the end of the quarter,” Aker BP said in a statement.
The company said production costs rose to $13 a barrel in the last quarter, partly due to its increased stakes in the Valhall and Hod fields and higher maintenance during the year.
Full-year production costs were $12.1 a barrel, in line with previous guidance.
Aker BP forecast these expenses would rise slightly in 2019 due to maintenance and modifications, especially at the Valhall and Ula fields.
The company, 30 percent owned by BP Plc, also said it would pay a quarterly dividend of $0.5207 per share amid strong cash generation from output growth. This was more than the $0.38 anticipated by analysts.
The increase came after the company said in January it would boost dividend payments between now and 2023, amounting to a total of $750 million in 2019 and up from $450 million a year earlier.
In total, the company’s so-called contingent oil and gas resources in discoveries grew by 23 percent in 2018 due to new acquisitions.
Aker BP, created in 2016 from the merger of Norwegian billionaire Kjell Inge Roekke’s oil firm Det norske and the Norwegian arm of BP, has grown rapidly to become the second-largest licence holder on the Norwegian continental shelf.
The company previously reported fourth-quarter production of 155,700 barrels of oil equivalents (boe) per day, up from 135,600 boe per day in the same period in 2017. It expects 2019 production at 155,000-160,000 boe, broadly in line with 2018.
Norwegian oil and gas firm Equinor raised its quarterly dividend and plans to boost capital spending in 2019 as it develops new fields in Brazil, the company said on Wednesday.
Equinor’s adjusted operating earnings before interest and tax rose to $4.39 billion in the fourth quarter from $3.96 billion during the same period of 2018, lagging a forecast of $4.8 billion in a Reuters poll of analysts.
For the full year 2018, adjusted earnings rose 42 percent year-on-year to $18 billion.
“We delivered record high production in 2018, and we are well positioned for profitable growth in the coming years. Internationally we are increasingly taking the role as operator, and we are strengthening Brazil as a core area for Equinor,” Chief Executive Eldar Saetre said in a statement.
Equinor reported lower-than-expected results as higher operational and exploration costs dragged down its operating profit in Norway, Biraj Borkhataria at RBC Capital Markets said.
“We suspect the market may react negatively initially to the earnings miss, with performance thereafter relying on Equinor’s ability to provide the market with confidence in its financial framework over the medium term, with implications for higher shareholder returns over time,” he added.
Equinor said it planned to pay a dividend of $0.26 per share for the fourth quarter, an increase from the $0.23 paid in recent quarters. Analysts had expected an unchanged dividend.
The company also said it expected to generate a total of $14 billion free cash flow over 2019-2021 at $70 a barrel, indicating a potential to raise dividends going forward.
The company, formerly known as Statoil, also said it planned to raise its capital expenditure to $11 billion this year from $9.9 billion in 2018, and will boost its spending on exploration to $1.7 billion from $1.4 billion, it added.
Equinor’s quarterly output stood at a record high of 2.2 million barrels of oil equivalent (mboe) per day, up from 2.1 mboe in the same quarter a year ago.
The quarterly production growth was mainly on account of portfolio changes and new wells, especially in the U.S. onshore, the company said.
The company expects to deliver an average annual production growth of around 3 percent from 2019 to 2025 as it prepares to bring Norway’s 2.2-3.2 billion barrels Johan Sverdrup oilfield onstream towards the end of 2019.
The production in 2019, however, is expected to remain broadly steady, it added.
Tests of the first shale well at Cuadrilla’s site in northwest England show a rich reservoir of high quality and recoverable gas, the British firm said on Wednesday, adding that rules that have constrained its testing work should be eased.
Cuadrilla is using a technique called hydraulic fracturing that involves injecting water and chemicals at high pressure to break up rock and extract gas. The practice, known as fracking, can cause tremors and environmentalists oppose the development.
The company repeatedly stopped operations last year at its Preston New Road site in Lancashire because of minor seismic events. British regulations demand work be suspended if seismic activity of magnitude 0.5 or more is detected.
Cuadrilla said it could only partially test the horizontal shale well because of the operating limits. It said it fully fractured 2 out of 41 stages along the horizontal well and less than 14 percent of sand was injected.
“Nonetheless the natural gas still flowed back from the shale at a peak rate of over 200,000 standard cubic feet (scf) per day and a stable rate of some 100,000 scf/day,” Chief Executive Officer Francis Egan.
Scaling up the results suggested a flow range of between 3 million to 8 million scf/day for a 2.5 km (1.6 miles) section once all stages were hydraulically fractured, Cuadrilla said.
“We have also confirmed that the Bowland shale formation fractures in a way that, from U.S. experience, is typical of an excellent shale gas reservoir,” Egan said.
REVIEW
Fracking techniques were pioneered in the United States, which has turned from an importer of gas to a net exporter.
Cuadrilla said more production data was needed to refine the preliminary results and this could only be done if seismicity limits are lifted to allow more effective fracturing.
The firm has asked the regulator to review rules on seismic activity to allow more thorough testing of exploration wells.
Depending on the outcome, Cuadrilla plans to complete fracking its first well at Preston New Road, start a second and carry out flow testing of both later this year.
Brazil’s state-run oil company Petroleo Brasileiro SA may reconsider its dividend policy, Chief Executive Officer Roberto Castello Branco told Brazilian newspaper Valor on Wednesday.
In an interview with the paper, Castello Branco said he may cancel quarterly dividends payments, to accelerate the reduction of Petrobras’ debt levels.
The Petrobras CEO also said the company expects capital expenditures of $16 billion this year, 23 percent higher than expenditures last year. Petrobras press representatives did not reply to a request for comment on the interview.
French energy major Total said its net adjusted profit rose 10 percent in the final quarter of 2018, lifting its full year earnings by more than a quarter after record oil and gas production.
Total said on Thursday that output reached an all-time high of 2.8 million barrels of oil equivalent per day in 2018 thanks to the start-ups of various operations and increased production in Australia, Angola, Nigeria and Russia.
It reported a 28 percent rise in full-year profit to $13.6 billion, following on the heels of strong results from other oil majors.
“These excellent results reflect the strong growth of more than 8 percent of the group’s hydrocarbons production,” Total’s Chief Executive Officer Patrick Pouyanne said in a statement.
On Tuesday, BP reported a doubling of profits, driven by strong growth in oil and gas output following a large U.S. shale acquisition.
Royal Dutch Shell, Exxon Mobil and Chevron also reported stronger-than-forecast earnings, driven by higher production in U.S. shale basins where Oil Majors have invested billions in recent years.
Total said its results would enable it to continue its shareholders’ return policy announced last year. After increasing dividends by 3.2 percent in 2018, it plans a 3.1 percent rise in 2019.
It will also buy back $1.5 billion of its shares in 2019 after buying back the same amount last year.
Total added it would eliminate its scrip dividend scheme from June 2019.
Oil major Total makes significant discovery offshore South Africa
French oil and gas major Total said it had made a significant gas condensate discovery after drilling its Brulpadda prospects on Block 11B/12B in the Outeniqua Basin, offshore South Africa.
Total said the Brulpadda well encountered 57 meters of net gas condensate pay in Lower Cretaceous reservoirs. The well was deepened to a final depth of 3,633 meters and has also been successful.
“With this discovery, Total has opened a new world-class gas and oil play and is well positioned to test several follow-on prospects on the same block,” Total’s senior vice president for exploration Kevin McLachlan said in a statement.
Brulpadda is one of several highly anticipated exploration prospects for the year. Total has said the field could hold between 500 million to over 1 billion barrels of oil equivalent.
Following the success of Brulpadda and confirmation of its potential, Total and its partners plan to acquire 3D seismic this year, followed by up to four exploration wells on the licence, the company said.
Total has a 45 percent working interest and is the operator of the Block 11B/12B which covers an area of 19,000 square kilometres. Other partners include Qatar Petroleum with a 25 percent stake, CNR International holds 20 percent and Main Street, a South African consortium 10 percent.
Egypt is moving ahead with ambitious programs to develop the country’s upstream sector by attracting international investments, even as production jumps from its landmark offshore gas field Zohr.
The ministry is looking at improving the investment environment in order to attract more international oil and gas companies to help produce more hydrocarbons, Tarek El Molla, Egypt’s Minister of Petroleum and Mineral Resources said at an event in Cairo ahead of the third edition of The Egypt Petroleum Show (EGYPS), which takes place from Feb. 11-13 in Egypt’s capital.
While its works to develop and modernise the petroleum sector, the ministry is also implementing a roadmap to develop and refine petroleum products locally. It aims to boost the downstream sector through creative ways of attracting investments from international companies, El Molla said.
Meanwhile, Egypt’s giant Zohr offshore gas field has raised output to 2.1 billion cubic feet per day (bcf/d) and partners in the project will invest $1.2 billion in fiscal year 2019/2020 to “intensify development activities in the Zohr area”, the petroleum ministry said, according to Reuters.
The largest gas field in the Mediterranean, Zohr was discovered in 2015 by Italy’s Eni and began output in late 2017. It contains an estimated 30 trillion cubic feet of gas.
Zohr development costs in fiscal year 2018/2019 (to end-June) are seen at $3.2 billion, the ministry said.
El Molla said the third edition of the show is a testament to the success in attracting international oil and gas companies, along with the support for the sector from Egypt’s President Abdel Fattah Al Sisi to develop and modernise the sector.
“Egypt’s government represented by the Ministry of Petroleum and Mineral Resources has played a vital role in promoting the energy sector through setting up strategic partnerships to benefit from its enormous resources potential, as it gears up to become the regional hub for energy,” said Christopher Hudson, president of dmg events, the organiser of EGYPS.
EGYPS is part of efforts being done to support Egypt as a regional destination for research and exploration investment in light of promising oil and gas prospects, the ministry said.
The conference sessions during EGYPS will discuss Egypt’s energy transformation roadmap, which prioritises the development of the country’s hydrocarbon resources.
Norwegian oil firm DNO reported on Thursday a higher-than-expected operating profit in the fourth quarter and said it would hike 2019 spending as it planned to drill a record number of wells.
The Oslo-listed firm, which produces most of its oil in the Kurdistan region of Iraq, in January won a hostile takeover bid for London-based Faroe Petroleum, expanding its foothold in the North Sea.
“The Faroe transaction transforms DNO into a more diversified company with a strong, second leg,” DNO’s Executive Chairman Bijan Mossavar-Rahmani said in a statement.
“This represents not a pivot away from Kurdistan but a pivot to Norway.”
The Faroe acquisition places DNO among the top five oil companies by production licenses held on the Norwegian continental shelf, which includes 22 operated licenses, DNO said.
The company said it would lift capital spending to $220 million (£170.2 million) in 2019, up from $138 million last year, and plans to raise total spending, including exploration spending, to $420 million, up 40 percent from the last year.
DNO’s drilling programme includes up to 20 exploration and production wells in Kurdistan, and another five wells in Norway. Including Faroe licenses, DNO plans to participate in up to ten wells in Norway this year, it added.
The company said it would publish pro-forma results and its 2019 investment programme for the combined entity later this month and in March.
It would continued to pursue other bolt-on acquisitions in Norway to complement its exploration and development programmes, it added.
Earnings before interest and taxes rose to $230 million in the fourth quarter from $25.7 million a year ago, beating a forecast of $68.5 million in a Reuters poll of analysts.
DNO’s working interest quarterly production stood at 91,570 barrels of oil equivalent
West Texas developers overbuilt capacity as fracking slowed, Midwest miners continue to lose market share to Texas rivals
Just a year after rushing into America’s busiest oil field with new mines, frack-sand producers may have overdone it.
West Texas sand used in the hydraulic fracturing process will drop 19 percent this year to about $30 a ton compared to 2018, according to industry consultant Rystad Energy AS. Sand pricing is a key financial input for oil explorers because fracking is the most expensive phase in drilling an oil well.
A slew of new West Texas mines close to Permian Basin drilling sites is elbowing Midwest mines that formerly dominated the frack-sand trade. Miners in and around Wisconsin that controlled 75 percent of the market in 2014 will see that diminish to 34 percent in 2020, Ryan Carbrey, Rystad’s senior vice president of shale research, told Petroleum Connection’s Frac Sand Industry Update conference in Houston on Wednesday.
“We do think that things continue to be rather sloppy from a pricing standpoint in 2019,” Chase Mulvehill, an analyst at Bank of America Merrill Lynch, said in a presentation during the conference. “We’ll see if people renegotiate contracts. What we’ve heard so far is people are actually starting to do that for some in-basin contracts.”
Fracking Demand
The sand oversupply has developed just as demand for fracking is taking a hit from the late-2018 slump in crude prices and more modest exploration programs by oil producers, Mulvehill said. Fracking demand is set to drop 3 percent in 2019, he said.
For Wisconsin sand, the price drop will be even more dramatic this year: Rystad is forecasting a 29 percent drop to $25 a ton.
Fracking involves blasting high-pressure jets of sand, water and chemicals underground to crack open oil- or natural gas-soaked rocks that don’t respond to traditional drilling methods.
Hi-Crush Partners LP, the first to open a mine in West Texas, said Wednesday in announcing fourth-quarter financial results that its Midwest mines felt the biggest pain from the Permian sand boom. And while the Houston company expects more high-cost mines to idle or close throughout the industry because of the heightened competition, it added that the so-called Northern White sand mined in Wisconsin is not dead.
"Different circumstances and preferences dictate what sand is used by individual E&Ps in particular basins and for specific completion designs," Chief Executive Officer Robert Rasmus told analysts and investors Wednesday on a conference call. "We continue to believe that Northern White sand will remain in demand at significant levels to meet growing frack sand needs in basins throughout the U.S."
New York investment firm Blackstone has funded a new company to provide water management and infrastructure services to oil and natural gas sites in the arid Permian Basin of West Texas.
Blackstone announced on Tuesday that firm's energy arm Blackstone Energy Partners LP has invested $500 million of private equity into the newly formed Waterfield Midstream LLC.
Headquartered in The Woodlands, Waterfield will focus on developing and acquiring water infrastructure projects ranging from delivering freshwater to hydraulic fracturing sites to treating, recycling and disposing of wastewater from oil and natural gas wells.
"We believe that Waterfield addresses a critical need of producers in the Permian Basin both in terms of infrastructure and quality of service," Blackstone Principal Erik Belz said in a statement. "Waterfield's subsurface capabilities and engineering track record set it apart from other offerings in the market."
Midstream Moves: Goodnight Midstream places Permian Basin saltwater pipelines into service
Waterfield is led by co-CEOs Scott Mitchell and Mark Cahill, who previously developed water infrastructure projects for Anadarko and Western Gas in the Permian Basin.
In addition to the investment from Blackstone, Mitchell and Cahill are launching Waterfield with two contracts in hand.
Waterfield holds a 15-year contract to provide wastewater gathering and disposal services for Midland oil company Guidon Energy in Martin County as well as a contract to operate water infrastructure and saltwater disposal for EagleClaw Midstream in Reeves County.
"They are both exceptional companies with technical expertise, operating excellence, financial discipline and integrity," Cahill said in a statement about the two contracts. "We believe Waterfield Midstream brings those same qualities to the water management market in the Permian Basin."
Midstream Moves: WaterBridge Resources secures $800 million for Permian Basin expansion
Water is quickly becoming a multi-billion business in the arid Permian Basin, where a number of companies have set up shop sourcing freshwater drilling and hauling, recycling and disposal of wastewater.
A byproduct of oil and natural gas production, water is often found with crude oil and natural gas in geological formations but because it is mixed with salts, metals, hydrocarbons and other compounds, it must either be cleaned or disposed.
Because of high costs to recycle and clean produced water, most companies choose to dispose of it by injecting it deep underground using saltwater disposal wells. Moving produced water via pipeline is considered a cost-saving and safer method than hauling it on tanker trucks from remote oil and natural gas wells.
More than 8,000 people are working day and night to bring the Gulf Coast’s third liquefied natural gas complex into operation within the next few months as global demand for LNG grows and U.S. natural gas production surges.
Sempra Energy of San Diego recently received clearance from the Federal Energy Regulatory Commission to begin the process of starting up its Cameron LNG project along the Calcasieu River Ship Channel here. Sempra officials won’t provide an exact estimate of how long the process could take. But if all goes well, the first of three production units that super-cool natural gas into a liquid could be up an running in as soon as a matter of weeks, with the first shipment to foreign customers to follow soon after.
The goal is to have all three production units in service by the end of the year and LNG on the way to destinations around the globe where it will be used for power plants, industrial customers and homes. The project is being developed as a joint venture between Sempra and four companies from Japan and France
“It’s an important project for Sempra Energy, it’s an important project for the nation and it’s an important project for the world,” Sempra Energy Strategic Initiative Officer Lisa Glatch said.
Cameron LNG is the latest milestone in the Gulf Coast’s emergence as global hub of LNG exports. Cheniere Energy has exported LNG from its Sabine Pass complex in Louisiana since 2016 and last year began shipping from a second complex near Corpus Christi. Meanwhile, several other projects stretching from Louisiana to Brownsville are advancing.
On Tuesday, Exxon Mobil and Qatar Petroleum, the state-owned oil company of the Middle East nation, said they would move ahead with the $10 billion Golden Pass LNG export terminal near Port Arthur.
Related: JV lands 'mega contract' to build $10 billion Golden Pass LNG export terminal
Cameron LNG’s three production units, which are known in the industry as trains, would produce nearly 12 million metric tons of LNG per year - enough natural gas to power around 10 million U.S. homes for a day. Originally developed as a $900 million LNG import terminal that began commercial operations in July 2009, Sempra decided to take advantage of record natural gas production from U.S. shale basins to get into the export game.
“As you well know, the world has changed we, some through Mother Nature and American technology and ingenuity, have a tremendous supply of natural gas,” Glatch said. “It’s clean burning and in high demand around the world especially from allies in Asia and Europe. Sempra is in a very natural place to step up and take a leadership role.”
Sempra entered into a joint venture with Japanese energy trading firm Mitsui & Co., French refining company Total, Japanese conglomerate and heavy equipment manufacturer Mitsubishi and Japanese shipping company Nippon Yusen Kabushiki Kaisha to develop the export terminal. nearly three years to obtain a federal permit for the project
The LNG export terminal will receive natural gas from Sempra’s Cameron Interstate Pipeline and TransCanada’s Columbia Gulf Transmission Pipeline. So far, crews have installed 1 million feet of pipe, about 7.5 million feet of cable and a quarter million cubic yards of concrete. Before construction on the plant could begin, crews raised the soil at the site 12 to 15 feet above sea level and brought in additional power lines and a substation to deliver 100 megawatts of electricity.
“It’s a huge civil engineering, construction, logistics and procurement effort,” Cameron LNG CEO Farhad Aharbi said. “It requires a lot of patience, a lot of dollars and a lot of know-how.”
The export terminal is just one of three facilities planned by Sempra as part of a two-coast approach to more export 45 million metric tons of LNG per year by the mid-2020s. In addition to Cameron LNG, the copmany is also developing the Energia Costa Azul LNG facility in Baja California, Mexico and seeking to develop another Gulf Coast LNG terminal Near Port Arthur.
As more nations switch from coal-fired power plants to natural gas, Glatch said demand for LNG is robust.
“In the mid-2020s, there’s expected to high demand and limited supply, that’s a good place to be for projects like ours,” Glatch said. “We’re ahead of the pack.”
The worldwide offshore rig count in January 2019 increased by five units sequentially and 50 rigs year-over-year, according to a Thursday report by Baker Hughes, a GE company.
BHGE splits its rig count reports on international and North America rig counts, which together make up the worldwide rig count.
Looking only at the offshore part, the international offshore rig count for January 2019 was 241, up 7 from the 234 counted in December 2018, and up 45 from the 196 counted in January 2018.
Breaking down the international count by regions, with only offshore rigs included, the rig count in Latin America lost one rig during January 2019 totaling 26 from 27 in December 2018 and remained flat compared to January 2018.
In Europe, the offshore rig count in January 2019 was 31, down 7 from 38 in December 2018 and up 4 rigs from January 2018.
Over in Africa, the offshore rig count for January 2019 was up by 5 rigs totaling 20 when compared to December 2018 and up 9 units from January 2018 which totaled 11 rigs.
In the Middle East region, the offshore rig count in January 2019 totaled 63 rigs, up 7 rigs from December 2018 and up 22 units from January 2018.
The Asia-Pacific region had the largest number of offshore rigs which totaled 101 in January 2019, up 3 rigs from December 2018 and up 10 rigs from January 2018.
In North America, there were 24 rigs in January 2019, down 2 from December 2018 and up 5 from January 2018.
The worldwide offshore rig count in January 2019 was 265, up 5 from 260 counted in December 2018, and up 50 from the 215 counted in January 2018.
France plans to back an EU proposal to regulate Russia’s Nord Stream 2 pipeline, its foreign ministry said on Thursday, potentially threatening its completion and dealing a blow to Germany which has been trying to garner support for the project.
The European Union executive wants to extend its internal energy market laws to offshore gas pipelines before construction is completed, giving it a say over how the new gas link under the Baltic Sea from Russia to Germany is used.
In its current form, Nord Stream 2, fully owned by Russian state energy firm Gazprom, would not be compliant with tougher new rules foreseen for new infrastructure projects.
Diplomatic sources said earlier that Germany had been pressuring other European capitals to block the new directive.
“France intends to support the adoption of such a directive. Work is continuing with our partners, in particular with Germany, on possible changes to the text,” French foreign ministry spokeswoman Agnes von der Muhll said in a briefing.
Any delay in building the pipeline would create uncertainty for Gazprom’s partners: Germany’s Uniper and BASF’s Wintershall unit, Anglo-Dutch Shell, Austria’s OMV and France’s Engie.
The EU bloc is divided in its support for the project. Eastern European, Nordic and Baltic Sea countries view the 1,225 km (760 mile) pipeline as holding the EU hostage to Moscow, while those in northern Europe, especially Germany, prioritizes the economic benefits.
An EU source said earlier that France’s vote would be decisive, likely leaving Germany short of a blocking minority.
The oil service market continues to show signs of recovery, Norway’s Aker Solutions said on Friday as the company reported a higher than expected order intake for the fourth quarter, while profits were in line with forecasts.
Order intake for the October-December period amounted to 5.3 billion Norwegian crowns, while analysts in a Reuters poll on average had predicted an intake of 4.9 billion.
Earnings before interest, tax, depreciation and amortization (EBITDA), excluding one-offs, rose to 495 million Norwegian crowns ($57.6 million) from 482 million a year ago, while analysts on average had expected 493 million.
“In 2018, we saw a record number of studies and front-end engineering work for larger and more complex projects than previous years - a positive sign of more work to come,” the firm controlled by billionaire Kjell Inge Roekke said in a statement.
Aker Solutions reiterated expectations for 2019 revenue to rise slightly from 2018, as well as continued high tendering activity with an underlying 2019 EBITDA margin seen remaining around the 2018 level.
The total backlog of outstanding work stood at 35.1 billion crowns, more than the 34.5 billion crowns expected by analysts in the Reuters poll.
Oil service firms such as Aker Solutions were hit by the plunge in crude prices from 2014-2016 when oil firms cut spending on new developments, and have since seen a gradual increase in orders.
Katanga Mining, which is a subsidiary of diversified major Glencore, says its cobalt debottlenecking project is progressing on schedule.
In an update to shareholders published on Friday, the Democratic Republic of Congo-based company said three new filter presses, a magnesium oxide reagent plant within the existing cobalt circuit and the construction of two cobalt hydroxide dryers are scheduled for completion and commissioning during the first quarter of this year.
Further, the commissioning of an acid plant at Katanga’s 75%-owned Kamoto Copper Company (KCC) subsidiary is expected to start in the fourth quarter of this year.
During the fourth quarter of 2018, the final components of Phase 2 of the KCC whole-ore leach project, being the remaining counter-current decantation circuit and the electrowinning tankhouse, were commissioned.
Meanwhile, Katanga’s copper cathode production increased to 152 358 t in 2018 from the 2 196 t produced in 2017.
Cobalt contained in hydroxide production increased to 11 112 t in 2018 from nil tonnes in 2017.
The export of cobalt hydroxide by Katanga’s KCC subsidiary remains suspended.
Katanga expects cobalt production for this year to reach 26 000 t, but the sale of cobalt is now only expected to resume in 2020.
Copper cathode production for this year is expected to reach 285 000 t.
RESOURCE UPDATE
Katanga has also announced an updated ore reserve and mineral resource estimate.
Overall, the measured and indicated mineral resource for KCC decreased by 7.9-million between December 2017 and December 2018, while its inferred mineral resource decreased by 2.9-million tonnes, as a result of depletion owing to mining activities in 2018.
http://www.miningweekly.com/article/katanga-advances-cobalt-debottlenecking-project-2019-02-01
Electric cars were the stars of the Detroit Auto Show this year and they have been garnering a lot of attention from the media generally amid increasingly urgent talk about climate change and how the world is failing in the fight against it. Every self-respecting automaker has at least one EV in the pipeline. The biggest ones have several. And all of these new EVs are scheduled to hit the market in the next few years. A pileup may be coming.
The pileup could be “of epic proportions” as AlixPartners warned in a study cited in a recent analysis of the EV topic by CNBC’s Paul Eisenstein. By the end of this year alone, Eisenstein says, analysts expect almost a dozen new EVs to make their appearance in showrooms across the United States. Some of these will be direct competitors of Tesla, which currently boasts an impressive 83 percent of the U.S. battery electric car market.
The “threat for Tesla” angle in EV reporting is a popular one and indeed a 83-percent market share is an unsustainable one in any industry. But with Tesla’s brand loyalty, concerns about the company’s future sales may be premature. What is not premature is a worry about that pileup AlixPartners warned about.
The world’s biggest carmakers are pouring billions into electric vehicles motivated by government incentives and strategies envisaging the phasing out of ICE vehicles in some markets. From the pro-EV perspective, the time is just right to launch as many electric cars as one can design and manufacture. All the big carmakers have developed EV manufacturing platforms and are preparing to put them to good use. Millions of EVs are coming to the market. There is just one problem with that: actual sales statistics.Related: Oil Rallies As Saudis Cut Exports To The U.S.
China is the world’s largest EV market, for example, with the total number of electric cars on Chinese roads last year reaching 2.61 million, which was up by 70 percent or more than a million cars from a year earlier. And yet, these 2.61 million EVs, according to Eisenstein, constitute just 4 percent of the total Chinese car market. Beijing has ordered local carmakers to boost their EV sales to 10 percent of their total sales this year and 12 percent in 2020, which means more competition for international rivals.
The United States, where sales of electric cars jumped by 81 percent last year, has just 1 million EVs on its roads. EV sales last year totaled around 360,000. This, however, compares with total car sales of over 17.2 million cars for the year. Putting the new EV sales figure in context shines a different light on the EV industry and this light becomes brighter when you factor in the federal tax incentives for EV manufacturers, which range between US$2,500 and US$7,500 per vehicle but are phased pout gradually once this manufacturer hits sales of 200,000 EVs.
So, despite the enthusiasm about electric cars they still continue to be a tiny portion of total car sales in the world’s biggest car market. Can this enthusiasm somehow drive increased EV adoption? Not on its own. In a Forbes article discussing trends in EVs in the U.S. this year, Energy Innovation policy analyst Amanda Myers noted a lot of people don’t want to switch to EVs because they are prohibitively expensive. Yet with battery costs falling—and they have been falling steadily and considerably over the past decade—electric cars are bound to become more affordable, spurring more purchases. Longer ranges—another key concern for buyers—will help boost adoption, too.
The question for all these manufacturers that are spending billions on EV R&D and production is whether this boost in adoption will be large enough to justify their investments.
The AlixPartners study estimated that “by 2023 a whopping $255 billion in R&D and capital expenditures (will be) spent globally on electric vehicles, and that some 207 electric models are set to hit the market by 2022.” It went on to warn that “many of them destined to be unprofitable due to currently-high systems costs, low volumes and intense competition.” One could only hope carmakers have factored in these risks in their EV strategies.
https://oilprice.com/Energy/Energy-General/Are-Automakers-Overestimating-EV-Demand.html
Summary
Gold is looking increasingly bright in 2019. Last year was a lackluster one for the price of gold, which seesawed as demand from investors ebbed and flowed. Gold prices reached a five-year-low at the end of the summer.
As expansion programs at South American brine operations slow down, the bulk of new lithium capacity is coming from hard rock mines.
While demand growth continues to accelerate the supply response has been dramatic. Last year saw four new spodumene operations enter the market and while concentrate (6% free on board Australia) traded either side of $900 a tonne for most of 2018, prices fell sharply in January.
According to industry tracker Benchmark Minerals combined output at these operations last year totalled over 175,000 tonnes and ramp up is continuing.
Apart from the new mines, Talison-Albemarle's Greenbushes spodumene mine, the world's largest, is doubling capacity and in January earthworks began on a massive new plant fed by the mine.
Any further decreases are expected to be marginal with many producers already operating at close to cost
Spodumene producers “experienced more pressure as 2018 contracts expired, ushering in a difficult period of negotiation for suppliers, as Chinese converters sought to receive significant discounts due to increased supply” says Benchmark:
With negotiations still ongoing for the limited volumes available outside of offtake agreements, prices as low as $620/tonne have been reported in the market – however this has largely been for small quantities of off-spec material.
The majority of volumes are being traded at $700-750/tonne for 6% Li2O spodumene concentrate, although there could be some further decreases when Chinese buying activity resumes from mid-February onwards.
While generally higher on the cost curve than brine operations, spodumene concentrate is converted into battery-grade lithium hydroxide which trades at around $16,000 per tonne ex-works in China, down from $20,000 six months ago.
Pumping and evaporating brine solution produces lithium carbonate which sometimes requires further refining or conversion to feed into the battery supply chain. Battery-grade lithium carbonate in China has halved in value over the past year and is now exchanging hands for under $12,000 a tonne.
At least the worst may be over for chemical prices says Benchmark:
“While these lower feedstock costs leave room for more reductions in Chinese chemical prices, any further decreases are expected to be marginal with many producers already operating at close to cost.”
http://www.mining.com/lithium-price-spodumene-getting-crushed/
A wave of profit warnings from several of China’s electric vehicle (EV) and associated component makers suggest that weaning the group from state support may be more painful than expected, with many companies now taking hits from purchases that were substantially overvalued.
Beijing wants to turn China into an EV powerhouse as part of a broader drive to promote cutting-edge technologies to clean up the country’s air and also create a new group of high-tech exporters. But its aggressive subsidies and other state support have created a bumper crop of players, many using older technologies with little opportunity for success.
Bolivia has chosen a Chinese consortium to be its strategic partner on new $2.3 billion lithium projects, the government said on Wednesday, giving China a potential foothold in the country’s huge untapped reserves of the prized electric battery metal.
China's Liu Jianfeng of Xinjiang TBEA Group Company, Juan Carlos Montenegro of Yacimientos de Litio Boliviano (YLB) and Jianlin He of America-Baocheng Desarrollo y Tecnologia del Salar shake hands after signing an agreement to produce lithium at the salt flat of Coipasa and Pastos Grandes in Oruro, Bolivia, February 6, 2019. Diego Valero/Courtesy of Bolivian Presidency/Handout via REUTERS.
China’s Xinjiang TBEA Group Co Ltd will hold a 49 percent stake in a planned joint venture with Bolivia’s state lithium company YLB, the Bolivian firm said.
Together, the companies will seek to produce lithium and other materials from the Coipasa and Pastos Grandes salt flats.
Bolivia estimates that development of the projects will cost at least $2.3 billion. The Chinese firm will provide initial investment and YLB will pay its share with future lithium production, YLB’s executive manager Juan Carlos Montenegro said by phone.
Bolivia has some of the world’s largest reserves of lithium - a key component in batteries that power electric cars - but has yet to produce the metal at a commercial scale.
The preliminary deal gives Beijing a fresh chance at locking in access to Bolivia’s lithium after German firm ACI Systems GmbH was chosen last year as partner on the country’s largest lithium deposit in the salt flats of Uyuni.
Xinjiang TBEA beat six rivals that also sought to partner with Bolivia on Coipasa and Pastos Grandes, including ACI, Uranium One - a subsidiary of Russia’s state nuclear company Rosatom - and the Irish company Clontarf Energy Plc.
“Why China? There’s a guaranteed market in China for battery production,” Bolivian President Evo Morales said in broadcast comments at a signing ceremony in the highland city of Oruro.
China, the biggest global consumer of lithium, will need 800,000 tonnes of the metal per year by 2025 to support its booming electric car industry, China’s Ambassador to Bolivia Liang Yu said at the same event, hailing the deal as “historic.”
There are no estimates yet for how much lithium Coipasa and Pastos Grandes hold. Bolivia said last month that a new study found that Uyuni likely has at least 21 million tonnes of lithium, more than double a previous estimate.
Despite its abundant reserves and growing global demand for the metal, Bolivia’s state-led plans to industrialize its lithium have faced repeated delays.
The next steps on Coipasa and Pastos Grandes will be to conduct feasibility studies, YLB said.
“This investment is not going to happen in a year. It’s a long process of several years,” Bolivia’s Deputy Minister of High Energy Technologies Luis Alberto Echazu said.
YLB added that it might partner with Xinjiang TBEA on a lithium battery plant in China.
Edmonton may spend $215 million to build a new composting facility to replace the troubled one that has been mostly offline since October 2017.
City council agreed at a meeting Tuesday to look at building a new facility.
Four alternatives were presented to city council in a report last week.
The proposed composter councillors appear to favour is more expensive to build, with an estimated cost of $215 million, but has a better expected return on investment, Coun. Ben Henderson said.
The composter would create renewable natural gas along with compost, he said.
The facility is expected to last 30 years, the report to council said.
The existing compost facility, built in 2000, would be torn down and the new one constructed on the same site.
The preferred composting technology is anaerobic digestion — which uses an airtight container to convert solid waste into methane and carbon dioxide, otherwise known as bio-gas.
"It's tested in other cities," said Coun. Michael Walters. "It meets our needs, possibly, pending further refinement in the business case."
Another proposed option called for repairs and upgrades to the existing facility, which has been mainly offline since 2017, when engineers discovered structural problems with the roof.
Coun. Michael Walters is an advocate of a modern waste management system for Edmonton, that includes organics pick up from the curb side. (CBC)
The roof can't handle the weight of snow, so the facility had to be shut down during the winter.
Council has asked the city operations department to do a complete business case on the favoured composting option and report back in October.
The facility would be one step in moving Edmonton into modern waste management, after the city's once stellar reputation took a beating last year.
"We rested on our laurels, as a waste management administration for some time," Walters said. "We didn't adapt to new technologies, we didn't recognize the importance of source separation."
The city will also embark on an organics pickup pilot project in the spring.
The goal will be to divert 90 per cent of solid waste from the landfill.
@natashariebe
https://www.cbc.ca/news/canada/edmonton/edmonton-city-council-composting-facility-1.5007334
LYON, France (Reuters) - A decade-old lawsuit in which a French farmer with neurological problems accuses Monsanto of not providing adequate safety warnings for a weedkiller returns to court on Wednesday, adding to health claims faced by the Bayer-owned firm.
French cereal farmer Paul Francois speaks to journalists as he arrives at the courthouse for the start of his appeals trial against U.S. Monsanto firm in Lyon, France, February 6, 2019. REUTERS/Emmanuel Foudrot
Paul Francois, who says he fell ill after inhaling vapor from weedkiller Lasso in 2004, won rulings in 2012 and 2015 that found Monsanto liable for the intoxication, before France’s top court overturned those decisions and ordered a new hearing.
An appeal court in the southeastern French city of Lyon will hear arguments on Wednesday before giving its verdict at a later date.
Francois, who says he has suffered memory loss, headaches and stammering, blames Monsanto for not giving sufficient warnings on the product label.
“Maybe we’ll lose against Monsanto but the real victory for me is that I have converted my 200-hectare farm to organic production,” 55-year-old Francois told reporters before the hearing.
“This affair made me open my eyes and move towards a different kind of agriculture.”
Lasso was banned in France in 2007 after the product had already been withdrawn in some other countries.
Bayer said it did not wish to comment specifically on the case until the ruling in the latest proceedings.
But it added in an emailed statement that “the use of phytosanitary products does not pose any risk for human health when they are used according to the terms defined as part of the product authorization.”
Monsanto, acquired by Bayer last year, is also facing lawsuits in the United States over alleged cancer links to glyphosate-based weedkillers. Lasso used a different active substance to glyphosate.
Last year, the company was found to be liable for the terminal cancer of a school groundskeeper who had used glyphosate-based products.
It is appealing that verdict but faces another U.S. trial next month relating to a couple suffering from cancer.
In France, a court last month banned a version of Monsanto’s Roundup weedkiller range on safety concerns.
Controversy over glyphosate has been fueled by a 2015 conclusion from the World Health Organisation’s cancer agency that the substance was probably carcinogenic.
Glyphosate was originally developed by Monsanto but it is off-patent and marketed worldwide by dozens of other crop chemical makers.
After a heated European Union debate in 2017 that led to a five-year renewal for glyphosate’s license, President Emmanuel Macron said France would aim to phase out the weedkiller in three years.
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[Countless lakes across the Southwest United States went dry in 2012, including this one, Teller Lake No.5, in eastern Boulder County, Colorado. Credit: UCAR, photo by Carlye Calvin.]
[NOAA Climate by Rebecca Lindsey] As part of their year-end national climate recap, the NOAA National Centers for Environmental Information reported on the stubbornness of extreme drought in the U.S. Southwest and Four Corners region in 2018.
The animated image below shows drought conditions across the contiguous United States every four weeks throughout 2018, starting with January 2 and ending with December 25. Places identified as “abnormally dry” are colored yellow, and increasing intensity of drought is shown in shades of orange to dark red.
According to NCEI’s report, a large area of extreme to exceptional drought dominated the Southern Plains early in the year, before improving during the summer, when drought intensified across Oregon and adjacent parts of the Pacific Northwest and Great Basin. Large parts of Colorado, New Mexico, Arizona, Utah and Oregon experienced drought throughout the vast majority of the year. Smaller parts of northern North Dakota, West Texas and Southern California did as well.
According to the U.S. Drought Monitor, drought coverage peaked at 39.6% of the contiguous United States in early February 2018. This coverage was largely attributable to intense drought stretching from the Southern Plains across the southern Rockies and Four Corners regions. A secondary peak of 35.7% in early August was driven by continued drought in the Four Corners region and a new center of drought conditions in Oregon and parts of the adjacent Northwest.
As the drought persisted, the impacts on people, agriculture, and natural landscapes piled up. According to news reports, the drought contributed to an intense fire season in northwestern Colorado, and for the first time in its history, the Yampa River (east of Dinosaur National Monument) was subject to a water “call:” all users whose water rights were granted since 1951 had to stop diverting any water from the river to protect the flows for more senior users.
Meanwhile, in New Mexico, surface water supplies dwindled to the point that parts of the Rio Grande were in danger of running dry. The U.S. Bureau of Reclamation had to broker a $2 million deal to lease groundwater from the Albuquerque Bernalillo County Water Utility Authority in order to keep minimum up minimum flows needed to protect endangered species.
The drought had abated somewhat as of early February (see image above), according to the U.S. Drought Monitor’s latest weekly report. But parts of the Four Corners remained stuck in extreme drought.
Edited for WeatherNation by Meteorologist Mace Michaels
http://www.weathernationtv.com/news/intense-2018-southwest-drought-lingers-into-this-year/
By Chinese industry estimates, the country has been producing well over 10 billion carats of diamond annually for almost a decade, but most of the products have gone to industrial use such as in abrasives.
Before foraying into consumer use, Chinese manufacturers provided them for aeronautics, oil rigs and electronic chips and honed their craft, said Hu Junheng, head of gemstone business at Henan Huanghe Whirlwind, which calls itself the world's largest synthetic diamond manufacturer with an annual production of 1.2 billion carats, mostly for industrial use.
As competition intensified and technology matured, these companies, mainly based in central China's Henan Province, have ventured from abrasives to jewelry.
The English-language "product list" of Henan Huanghe Whirlwind now starts with "superhard materials" and ends with "Lab-Grown Diamond (Gem Quality)".
Liu Yongqi, general manager of Sino-Crystal, another Henan-based company, said it now produces between 2 million and 3 million carats a year, over half of which are for jewelry.
"We began our transformation in 2014 to expand to gem-grade diamonds," said Liu, citing over-competition for industry use and a "blue sea" consumer market.
"It is important to understand that even if synthetic diamond production is initially lower quality, the diamonds can be 'enhanced' with processes that turn lower quality goods into higher-quality," Paul Zimnisky, an independent diamond analyst in New York, told Xinhua.
If even a fraction of Chinese production is upgraded to jewelry-quality diamonds, it would have a very significant impact on the global supply which is only in the low-millions-of-carats, Zimnisky said.
"China, and by extension Asia, is the main producer of synthetic diamonds," Margaux Donckier, spokeswoman for Antwerp World Diamond Center, told Xinhua. "Synthetic goods only represent about 3-5 percent of the [consumer] market, but the share is growing rapidly."
ICE IN A FRIDGE, ICE IN A RIVER
A major boost to man-made diamonds, Chinese manufacturers said, came from De Beers, the dominant giant that popularized the saying, "a diamond is forever."
Reversing its previous position of shunning the man-made sector, De Beers took a U-turn in 2018 by selling man-made diamonds through its Lightbox Jewelry brand.
"Since De Beers embraced man-made diamonds, the market has been developing rapidly," said Liu, citing expanding sales in Japan and recent visits to his company from major jewelry brands.
Man-made diamonds' growing prospects are their increasing quality at decreasing cost. It is now impossible to tell a man-made diamond from a mined one with the naked eye, despite the latter's exorbitant price.
Experts with professional equipments can distinguish the two, but that distinction is so irrelevant to the Federal Trade Commission of the United States, that the previously specified "natural" origin within the FTC's definition of a diamond was removed in 2018.
In its Guides for the Jewelry, Precious Metals, and Pewter Industries, the FTC ruled "based on changes in the market, the final Guides eliminate the word 'natural' from the definition of diamond...because lab-created products that have essentially the same optical, physical and chemical properties as mined diamonds are also diamonds."
Zang Chuangyi, a scholar at Henan Polytechnic University, believes a diamond is a diamond no matter how it was formed -- grown in a lab or mined out of the ground.
"It's like comparing ice in a fridge at your home, with ice in a river," Zang said.
ONLY AS FASHION JEWELRY?
But in the view of De Beers and others with ties to the established diamond profession, there are still insurmountable differences between man-made diamonds and mined ones.
"Our research consistently shows that people see synthetic diamonds as a different product category from natural diamonds, just as they see synthetic rubies, emeralds and sapphires as different product categories from their natural counterparts," the company told Xinhua in a statement.
It is with convictions like this that De Beers decided to wade into men-made diamonds, intending to grab a growing sub-market and in the process solidifying the perception that man-made diamonds are inferior to mined ones, which will also safeguard its original business, experts said.
The Antwerp World Diamond Center largely follows the prevailing rationale in this regard, spokesperson Donckier said. "Diamonds and synthetic diamonds should be seen as two different products. They are certainly not interchangeable."
Current regulations in China and elsewhere require that man-made and natural diamonds are clearly labeled so that consumers know what they are buying.
Man-made diamond jewelry will fall into the category of "fashion jewelry" while natural diamonds will remain "fine jewelry," Zimnisky said.
But there are also outliers who say a diamond should not be forever even from the beginning, and consumers, many of whom are increasingly budget conscious, already have too many bills to pay excluding an overhyped and overpriced stone.
Yonden Lhatoo, the chief news editor at the Hong Kong-based South China Morning Post, wrote in a scathing column: "Anyone with a basic education should know by now that the ridiculous tradition of men having to buy diamond engagement rings for women before marriage was wholly concocted."
Diamonds are such a waste of money, he wrote: "If you must buy a diamond, it makes much more sense to go for a lab-manufactured one."
HUGE POTENTIAL AHEAD
The man-made diamond jewelry market will grow 22 percent annually from 1.9 billion U.S. dollars to 5.2 billion by 2023, Zimnisky said.
Liu, of Sino-Crystal, said that man-made diamonds might not cannibalize sales of mined diamonds, but that market alone boded well for Chinese manufacturers.
"Could they compete with De Beers? Yes, they certainly could. It just concerns technology that almost anyone can obtain these days, so why could a Chinese manufacturer not make the same product as well as anyone else?" Donckier said.
"The quality of Chinese synthetic diamond production appears to be advancing quite rapidly from what I am seeing. I have seen some Chinese product that rivals that of Lightbox," Zimnisky said.
SMM copper downstream PMI fell to 48.43 for Jan, down from 50.14 in Dec
https://news.metal.com/newscontent/100873514/china-copper-downstream-pmi-falls-to-4843-ahead-of-cny/
China Hongqiao Group, the world’s top aluminium smelter, said on Friday it would gradually restart production from some of its pots after the shorter set of winter output curbs expired on Jan. 31.
Some of the restrictions on Hongqiao’s winter output were to run for four months from mid-November to mid-March but others only applied to December and January.
In a statement to Reuters, the company said it would take around four months, until June, to fully resume production from the pots now being restarted. Around 100,000 tonnes of aluminium production had been affected by the winter cuts, it added.
Once-in-a-century flooding in part of the eastern Australian state of Queensland looks set to worsen as the nation’s weather bureau on Saturday warned of more heavy rain in the area.
Some residents have already been evacuated after days of monsoon rains lashed the region around the coastal city of Townsville in north Queensland, a spokesman for the Bureau of Meteorology said.
Adam Blazak, a forecaster with the bureau, did not say how many people had been evacuated, but added that some areas had reached “major” flood levels.
“Normally a monsoonal burst might last a few days, but this one’s been going on over a week now and is set to continue for a few more days as well,” he said.
Between 150 mm and 200 mm of rain is expected across Townsville on Saturday - equal to about a month’s average rainfall.
Local authorities issued a number of flood warnings on Saturday morning and told residents to avoid using roads and consider moving to higher ground if conditions worsen.
North Queensland has significant zinc reserves as well as major deposits of silver, lead, copper and iron ore, with Townsville a major processing center for the region’s base metals.
Zambia is determined to enforce a new 5 percent copper import duty, as part of a plan to keep a greater share of mineral resource profits for the country and tackle its debt, Mining Minister Richard Musukwa said.
Musukwa was speaking on the sidelines of the Indaba mining conference in Cape Town, where government ministers and mining executives are debating how to attract investment and how to strike the right balance between resource-holding governments and foreign companies.
Vedanta has said it would suspend operations in Zambia, although the minister said it had yet to do so, while Barrick has said it is exploring options for its Zambian copper mine. Vedanta declined to comment on Monday.
Musukwa said he was open to dialogue with the international miners and Zambia, Africa’s second-biggest copper producer, would remain a stable investment regime with no plans to increase state ownership.
“We appreciate that the investors are bringing in resources. They are bringing in expertise. We keep a small percentage for checks and balances and currently it sits around 15 to 20 percent. We have no plans to increase beyond those measures,” he told Reuters in an interview.
The new taxes, which also include a royalty on copper production that increases as commodity prices rise, were “well-thought-out and logically calculated with the inputs of stakeholders, even the mining companies”, he said.
Most miners had accepted them, he said, but he was talking to mining executives, including the CEO of Barrick, in Cape Town about some of their concerns.
“The government is open for discussion. These taxes are not meant to be one size fits all,” he said, while saying he was determined to stick with a tax on imported copper concentrate produced from rough ore.
“As we see it, the government is resolved that mining houses have to pay for that,” he said, referring to the 5 percent import levy.
“They don’t need to import. They must develop their licences. They must employ our people and improve our economic performance.”
Mark Bristow, CEO of Barrick Gold Corp, told reporters in Cape Town the new taxes had put its Zambian copper mine “under pressure”.
“Zambia should be a preferred place for investors to go and mine copper,” he said.
Vancouver-based First Quantum already owns 80 percent of the Kansanshi mine in Zambia’s North-Western Province, while state-owned ZCCM Investments Holdings Plc holds the rest. The proposal, which was submitted last year, includes $300 million to $400 million in cash, and an equal amount in special royalties, over more than 10 years, said the people, who asked not to be identified because they’re not authorized to comment.
Kansanshi is First Quantum’s biggest mine, and accounted for more than half the company’s revenue in 2017.
First Quantum spokesman John Gladston declined to comment. Amos Chanda, Zambian President Edgar Lungu’s spokesman, didn’t immediately respond to a call and message seeking comment, and neither did a spokeswoman for ZCCM-IH.
The deal would also include ZCCM-IH dropping a $1.4 billion legal claim against First Quantum over a loan the company received from Kansanshi, the people said. The government is still considering the proposal, according to one of the people.
First Quantum and the government have been at loggerheads over other issues too. The country’s revenue authority handed it a $7.9 billion tax bill last year, while an increase in royalties this year prompted First Quantum to announce plans to fire 2,500 workers. The company has since backtracked on the proposal.
Kansanshi is First Quantum’s biggest mine, and accounted for more than half the company’s revenue in 2017.
http://www.mining.com/web/first-quantum-said-offer-700m-zambia-mine/
Swedish mining equipment maker Epiroc reported quarterly order intake and underlying profitability slightly below analyst forecasts on Tuesday and said it expected near-term demand to remain at the current level.
The company, spun out of industrial group Atlas Copco last year, said order intake rose to 9.47 billion Swedish crowns ($1.04 billion) from 8.06 billion in the year-ago quarter, just below the 9.56 billion seen in a Reuters poll.
It reported an adjusted operating margin of 20.4 percent, slightly below the 20.6 percent seen by analysts.
“While we expect demand to continue to remain at the current level in the near-term, there are uncertainties related to the development of the economic cycle and global trade tensions,” Epiroc Chief Executive Per Lindberg said in a statement.
Epiroc’s Swedish rival Sandvik reported quarterly results just ahead of market forecasts in late January buoyed by strong demand and profitability in its mining unit.
Epiroc’s fourth-quarter operating earnings rose to 2.16 billion crowns from 1.53 billion in the same quarter a year earlier and above the 2.05 billion mean forecast.
It was encouraging for miners when Simon Moores, managing director, Benchmark Mineral Intelligence, testified before the U.S. Senate Committee on Energy and Natural Resources on Tuesday.
Moores was summoned by the Senate Committee to testify on the lithium, cobalt, nickel and graphite supply chains for energy storage.
"Benchmark Mineral Intelligence is now tracking 70 lithium ion battery megafactories under construction across four continents, 46 of which are based in China with only five currently planned for the US. When I gave my last testimony in October 2017, the global total was at 17," Moores said.
Moores said that these megafactories are being built almost exclusively to make lithium ion battery cells using two chemistries: nickel-cobalt-manganese (NCM) and nickel-cobalt-aluminium (NCA).
“This means the supply of lithium, cobalt, nickel and manganese to produce the cathode for these cells, alongside graphite to produce battery anodes, needs to rapidly evolve for the 21st century," Moores testified.
Moores presented a chart based on the assumption that all of these megafactories are built and run at 100% capacity utilization.
"Under this scenario, lithium demand will increase by over eight times, graphite anode by over seven times, nickel by a massive 19 times, and cobalt demand will rise four-fold, which takes into account the industry trend of reducing cobalt usage in a battery," Moores testified.
Also on Tuesday, Benchmark Mineral Intelligence launched lithium carbonate and hydroxide price indexes, which draw from the data collected by analysts across 11 market prices. See more on price boosts here.
http://www.mining.com/battery-megafactories-buildout-nickel-demand-19-fold-benchmark/
Bitcoin and other cryptocurrencies are the most popular application of blockchain technology. When you hear the word blockchain, the first thing that will come to your mind is ‘Bitcoin” or ‘cryptocurrency’. This is because Bitcoin was the first technology to be created on a blockchain. Over time, new use cases of blockchain technology were discovered. One of the most popular use cases outside the cryptocurrency industry is supply chain and logistics tracking.
Blockchain Technology Used To Track Biofuel
BHP, a multinational oil and metal mining giant has successfully completed a biofuel delivery process on a blockchain. This was done as part of the company’s experiment with NYK, a Japanese shipping company. The biofuel that was used for the experiment was provided by GoodFuels, one of the leading providers of sustainable biofuel in the world. The blockchain-based system that was used for the experiment was created by BLOC, a blockchain development company in the maritime industry.
Bitcoin (BTC) Price Today – BTC / USD
Name Price 24H (%) $3,399.75 -1.87%
The biofuel was delivered to Frontier Sky, the BHP-chartered carrier owned by NYK. The carbon dioxide savings during the transportation was verified using a blockchain-based platform. The biofuel, according to Dry Bulk, is an alternative to typical fossil fuels. This helps reduce greenhouse carbon emissions significantly. If driving a car was used to determine the difference, it would be a ride of 125,000 miles. These savings in carbon emissions are especially important at this time because of the increasing damage of global warming.
Dry Bulk stated that the experiment is a big deal because it marks an important step for NYK and BHP per the global decarbonization policy. It also showed how blockchain technology can help increase transparency in supply chains. In the industry, it can be used during the shopping process to determine the origin, and fuel quality as well as verify reductions in emission.
Blockchain Technology In The Maritime Industry
This isn’t the first move blockchain technology is making into the maritime industry. Recently, many major shopping companies and ports have been exploring blockchain technology for tracking shipments and improving overall efficiency.
Last year, Associated British Ports, a United Kingdom port operator, entered a partnership with Marine Transport International, a digital logistics operator. The goal was to reduce the time required by its employees to process data.
A while ago, Zim, the biggest cargo shipping company in Israel, launched a blockchain-based platform. The platform is used for making electronic lading bills for clients during trades. The company decided to go ahead with the product after a successful trial.
In August last year, Danish transport, Maersk, and IBM came together to launch a global shipping solution that is based on blockchain technology. The platform involved 94 big organizations from around the globe.
Do you think blockchain technology is going to keep making waves in the supply chain industry throughout the year 2019? Share your comments.
Japanese trading house Sumitomo Corp booked one-off losses of about 15-billion yen ($137-million) on the Ambatovy nickel/cobalt project in Madagascar in the October to December quarter and cut its nickel output estimate for the current year for the project.
The losses include about 10-billion yen due to lower-than-expected production and about 5-billion yen on the disposal of some fixed assets and appraisal of ore inventories, Sumitomo CFO Koichi Takahata told a news conference.
For the current business year to end-March, Sumitomo lowered its estimate of Ambatovy's nickel output to 38 000 t to 40 000 t from 40 000 t to 43 000 t.
Takahata said output is expected to grow to around 46 000 t next year starting in April. Sumitomo owns a 47.67% stake in the project, while Canada's Sherritt International and South Korea's Korea Resources also hold stakes in the project.
Lead prices may get a boost as environmental crackdowns on smelters in China curb output in the world’s biggest market for the battery metal as inventories tumble.
A record-breaking cold blast in United States could deepen potential shortages, creating a spike in demand as drivers scramble to replace batteries damaged by the big freeze.
Benchmark lead prices on the London Metal Exchange have gained around 4 percent this year after sliding 18.8 percent in 2018, its biggest annual loss since 2011.
Lead inventories in warehouses registered with the LME have slid by a third over the past month to the lowest levels since April 2009, while metal stored in Chinese non-exchange depots have tumbled by 70 percent.
Two years of weaker mine output have resulted in global market deficits, with the gap mainly made up by inventories, but these are now running very low, said Farid Ahmed, lead analyst at consultancy Wood Mackenzie.
Inventories cover just over one week of global lead demand.
“There’s not a lot of lead around. We could see some fireworks in the next several months, there could be an acute squeeze,” Ahmed said.
A clampdown on polluting smelters in China has resulted in a significant proportion of smelters idle or operating at reduced rates, he added.
Last year, primary lead output in China fell 2.3 percent. While secondary, or recycled, lead production increased by 5.9 percent and offset that decline, this year the authorities are launching a crackdown on illegal lead battery recycling.
The recent U.S. cold snap could also exacerbate the situation. “We note that 40 percent of auto battery demand arises from replacement – which tends to peak in the winter months as battery failures increase,” Robin Bhar, head of metals research at Societe Generale, said in a note.
The shutdowns have helped spur a sharp rise in Chinese imports of refined lead.
But after the major erosion of LME stocks, what’s left in LME warehouses is old, low quality metal that is largely not suitable for Chinese battery makers.
“You’ve got this big China pull, really extreme China tightness at the moment, but there’s a very big quality deferential between the metal that’s attracted into China and most of the metal that’s left on the LME.” said Oliver Nugent, analyst at Citibank in London.
Mine production is due to recover this year, but there is a lag as unprocessed ore works its way through the value chain into refined metal and therefore will not help the market in the next few months, analysts said.
The International Lead and Zinc Study Group forecast that lead mine supply is due to increase this year by 4.1 percent to 4.77 million tonnes after falling 0.4 percent in 2018.
Any squeeze should be temporary, since mine supply is due to continue to increase, leading to a global surplus of 106,000 tonnes by 2020 and 109,000 tonnes the following year, according to Citibank.
Norwegian aluminium producer Norsk Hydro reported on Thursday much lower-than-expected fourth-quarter operating profits and full-year dividend amid continuing output restrictions in Brazil.
Hydro’s underlying operating profit for the quarter fell by 85 percent year-on-year to 534 million Norwegian crowns ($62.48 million), while analysts in a Reuters poll on average had expected a profit of 1.45 billion crowns.
Brazil last year forced the company to slash output from its Alunorte alumina refinery by 50 percent following a spill of untreated water from the facility, the world’s largest of its kind and a key supplier to Hydro’s metal smelters.
Last month, the Brazilian state of Para lifted its part of the restrictions, but full production at Alunorte can only resume once a federal court follows suit, Hydro has said.
“Our results are reflecting the challenging situation we face in Brazil and higher raw material costs,” Chief Executive Svein Richard Brandtzaeg said in a statement.
Alunorte had made progress towards resuming normal production but the timing remained uncertain, he added.
Hydro’s board proposed a dividend of 1.25 crowns per share for 2018, down from 1.75 crowns for 2017, while analysts on average had predicted a 1.58 crown payout.
Verification of the hefty bill submitted by British developer of Turkana oilfields Tullow Oil as costs to be recovered from Kenyan oil exports has taken longer than expected, delaying the much anticipated audit results.
The Petroleum Ministry said that the audit was “an involving process and ongoing” and that the exercise would be completed “soon.”
Last year, Kenya picked Alexandria-based Swale House Partners to undertake the audit covering six years of Tullow costs in Lokichar Basin between 2010 and 2016.
The audit was to take six months from June to December last year, a deadline that has now been breached by two months.
The audit results will inform the ministry on how much the oilfield developers will recover from sale of crude oil once commercial production kicks off. Tullow’s expenses claim stands at Sh200 billion to be defrayed from oil sales should the figure be verified. This means the share of oil rents due to Kenya stands to shrink.
Earlier, the ministry said that should the audit establish a lower cost burden than the one quoted by Tullow in its financial statements, the company would have no choice but to revise it downward.
The British firm together with its partner Africa Oil of Canada indicate that $2 billion (Sh200 billion) has been spent so far in developing Turkana oilfields since 2010 when wells exploration started.
The companies will claim compensation for this hefty expenses bill, along with future infrastructure spending, when oil revenues start flowing in.
The larger their claims, the narrower the share due to Kenya.
It’s for this reason that the government decided to conduct an independent audit to probe the numbers.
Tullow struck Kenya’s first oil in Turkana’s Lokichar basin in northwest Kenya in 2012 and followed it with a string of other finds. This has put the country on the path to becoming a producer of the black gold.
So far, some 750 million barrels of recoverable oil has been struck with further expeditions ongoing, an exercise that looks set to yield over 1 billion barrels of crude
http://energysiren.co.ke/2019/02/07/audit-results-for-tullow-expenses-in-turkana-oilfields-delayed/
Major non-ferrous metal reported faster total output growth in China last year, official data showed.
The production of 10 types of non-ferrous metal increased 6 percent year on year to 56.88 million tonnes in 2018, picking up pace from the 3-percent increase in the previous year, according to the National Development and Reform Commission.
The acceleration was mainly driven by robust production of electrolytic aluminum, which accounted for nearly two-thirds of the total output. Its growth sped up significantly from 1.6 percent in 2017 to 7.4 percent last year.
The production of copper and lead increased 8 percent and 9.8 percent, respectively. But the production of zinc dropped 3.2 percent.
However, the combined profits in the non-ferrous metal industry dropped 6.1 percent year on year to 185.5 billion yuan (27.65 billion U.S. dollars), weighed down by a lackluster metal smelting and rolling sector and falling prices.
Canadian miner First Quantum has signed a new $2.7-billion term loan and revolving credit facility, replacing the existing $1.5-billion revolving credit facility.
Underwritten by three core relationship banks, the new $2.7-billion facility, with an accordion feature to increase it up to $3-billion before the end of 2019, comprises a $1.5-billion term-loan facility and a $1.2-billion revolving credit facility maturing on December 31, 2022.
The refinancing extends the debt maturity profile of the business, eliminating all material debt maturities through to 2022. In addition, it provides liquidity headroom under the revolving credit facilities.
The facility will be used for the redemption of the $1.12-billion senior notes due February 2021, in full or in part and for general corporate purposes.
http://www.miningweekly.com/article/first-quantum-announces-refinancing-2019-02-07
Russian aluminium producer Rusal said Friday its aluminium production in 2018 rose 1.3% from a year ago to 3.8 million tons, while sales volume fell 7.2% to 3.7 million tons. Value added products, or VAP, accounted for 45% of the total sales.
Rusal said that in 2018, the average aluminium realized price was $2,259/mt, about 7.3% higher than the previous year at $2,105/mt.
In the fourth quarter last year however aluminium prices, along with other metals on the London Metal Exchange, fell due to investor sell-off amid US-China trade tensions, it said.
The company, however, maintained that the aluminium market was in deficit and the price has upside potential, citing the decrease in LME stocks, and the fall in the Chinese aluminium production in 2018.
"Around 50% of aluminium production facilities outside of China and 60% are making losses," it said.
Rusal's production in Q4 was 943,000 mt, up 0.4% from the previous quarter.
Plant utilization rate at its ten smelting plants was stable at 96% in the second half of the year.
Rusal reported a drop in sales of 16.2% to 877,000 mt, due to a 32.4% decline in VAP which was affected by the US sanctions.
"VAP sales in the fourth quarter were significantly challenged by short [US] Office of Foreign Assets Control General License extensions," it said.
Rusal's 2018 alumina production was 7.8 million tons, flat from 2017.
"In June, Rusal restarted operation of the Friguia refinery in Guinea. As a result, despite weather affecting the Windalco capacities performance, overall production remained similar to 2017," it said.
Russian aluminium giant Rusal expects demand for aluminium to grow in 2019 and sees potential for prices to rise, it said on Friday, sending its Hong Kong-listed shares up 12 percent to a 10-month high.
AK Steel (NYSE:AKS) issued an update on its FY19 earnings guidance on Monday morning. The company provided earnings per share guidance of $0.51-0.57 for the period, compared to the Thomson Reuters consensus earnings per share estimate of $0.64. AK Steel also updated its FY 2019 guidance to $0.51-0.57 EPS.
Shares of AKS traded up $0.07 during trading hours on Tuesday, reaching $3.07. The company’s stock had a trading volume of 174,122 shares, compared to its average volume of 10,936,418. AK Steel has a 1-year low of $2.05 and a 1-year high of $6.14. The company has a market capitalization of $959.24 million, a price-to-earnings ratio of 4.75, a P/E/G ratio of 0.98 and a beta of 2.73. The company has a debt-to-equity ratio of 4.64, a current ratio of 1.95 and a quick ratio of 0.69.
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AK Steel (NYSE:AKS) last announced its earnings results on Monday, January 28th. The basic materials company reported $0.16 earnings per share (EPS) for the quarter, topping analysts’ consensus estimates of $0.11 by $0.05. The firm had revenue of $1.68 billion during the quarter, compared to analysts’ expectations of $1.70 billion. AK Steel had a return on equity of 54.01% and a net margin of 2.73%. The company’s revenue was up 12.1% on a year-over-year basis. During the same quarter in the prior year, the business earned ($0.06) earnings per share. Equities research analysts expect that AK Steel will post 0.6 earnings per share for the current fiscal year.
A number of brokerages recently commented on AKS. Longbow Research lowered AK Steel from a buy rating to a neutral rating and set a $2.77 target price for the company. in a research note on Wednesday, January 30th. Cowen assumed coverage on AK Steel in a research note on Tuesday, January 8th. They issued a market perform rating and a $2.50 target price for the company. Macquarie lowered AK Steel from an outperform rating to a neutral rating and set a $3.00 target price for the company. in a research note on Tuesday, January 29th. Morgan Stanley set a $5.00 target price on AK Steel and gave the company a buy rating in a research note on Wednesday, November 7th. Finally, Bank of America lowered AK Steel from a buy rating to an underperform rating and lowered their target price for the company from $5.00 to $2.50 in a research note on Wednesday, January 30th. Five equities research analysts have rated the stock with a sell rating, eight have given a hold rating and two have given a buy rating to the company. The company presently has an average rating of Hold and a consensus price target of $4.09.
In other news, CEO Roger K. Newport bought 10,000 shares of the company’s stock in a transaction that occurred on Tuesday, November 27th. The shares were acquired at an average price of $3.03 per share, with a total value of $30,300.00. Following the transaction, the chief executive officer now owns 461,297 shares in the company, valued at $1,397,729.91. The transaction was disclosed in a document filed with the Securities & Exchange Commission, which can be accessed through this hyperlink. 1.13% of the stock is currently owned by company insiders.
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About AK Steel
AK Steel Holding Corporation, through its subsidiary, AK Steel Corporation, produces flat-rolled carbon, stainless, and electrical steels, and tubular products in the United States and internationally. It produces flat-rolled carbon steel products, including coated, cold-rolled, and hot-rolled carbon steel products; grain-oriented specialty stainless and electrical steels; and carbon and stainless steel tubing products.
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https://www.fairfieldcurrent.com/news/2019/02/05/ak-steel-aks-updates-fy19-earnings-guidance.html
On February, 12. Investors expect Arch Coal, Inc. (NYSE:ARCH) to report its quarterly earnings, according to Faxor. This year’s EPS analyst estimate is awaited to be $3.19. That is 22.57 % down compareed to $4.12 EPS for last year. This could reach $59.95 million profit for ARCH assuming the current $3.19 EPS will become reality. Analysts at Wall Street see Arch Coal, Inc.’s -49.61 % negative EPS growth compared to $6.33 EPS for last quarter. The stock increased 0.10% or $0.09 during the last trading session, touching $88.22.Arch Coal, Inc. has volume of 194,679 shares. Since February 3, 2018 ARCH has risen 0.87% and is uptrending. ARCH outperformed by 0.87% the S&P 500.
Arch Coal, Inc. produces and sells thermal and metallurgical coal from surface and underground mines.The firm is worth $1.66 billion. The companyÂ’s flagship mine is the Leer Complex located in Taylor County, West Virginia.The P/E ratio is 6.13. As of December 31, 2016, it operated 12 active mines located in West Virginia, Kentucky, Virginia, Illinois, Wyoming, and Colorado.
For more Arch Coal, Inc. (NYSE:ARCH) news released recently go to: Benzinga.com, Zacks.com, Seekingalpha.com, Businesswire.com or Seekingalpha.com. The titles are as follows: “The Best Coal Stocks February 2019 • Benzinga – Benzinga” released on November 08, 2018, “Why the Earnings Surprise Streak Could Continue for Arch Coal (ARCH) – Zacks.com” on January 25, 2019, “Arch Coal, Inc. (ARCH) CEO John Eaves on Q3 2018 Results – Earnings Call Transcript – Seeking Alpha” with a publish date: October 23, 2018, “TPG Specialty Lending, Inc. Expands its Board of Directors and Elects Hurley Doddy and Jennifer Gordon to the Board – Business Wire” and the last “Arch Coal Is Back After Exiting Bankruptcy In 2016 – Seeking Alpha” with publication date: March 26, 2018.
https://ztribune.com/2019/02/03/as-of-february-12-the-eps-for-arch-coal-inc-arch-expected-at-3-19/
Smoke rises from a coal-fired power station near Johannesburg, South Africa, 30 December 2015. The station is owned and operated by the state-run Eskom. Over 80 percent of electricity produced in South Africa is generated from coal-fired power station, making use of the rich coal deposits in the country and placing South Africa among top 20 carbon dioxide emitting countries. EPA/KIM LUDBROOK
FirstRand Bank has joined the exodus of local banks that had been funding new coal-fired power plants in South Africa, and in particular the Thabametsi and Khanyisa independent power producer projects.
These two projects are included in the draft integrated resource plan for electricity, Draft IRP 2018, for completion in 2023 and 2024. The IRP is due to be presented to the Cabinet for final approval in February 2019, according to Minister of Energy Jeff Radebe.
The 557MW Thabametsi project and 306MW Khanyisa project were announced as the successful bidders in October 2016, in the first bid window of the Department of Energy’s new-coal independent power producer (IPP) programme, after a request for proposals in December 2014.
The projects have still not achieved financial close, and in addition to funding difficulties, their environmental authorisations, atmospheric emission licences, water-use licences and generation licences are either outstanding or being challenged in various forums, including the high court.
Following an earlier article by EE Publishers detailing the withdrawal of Nedbank and Standard Bank from funding the Thabametsi and Khanyisa projects, FirstRand bank has now advised that it too has withdrawn from funding the project in which it was involved, Thabametsi.
“Please note that on 26 November 2018 FirstRand Bank Limited withdrew from financing the Thabametsi coal-fired power plant as currently proposed”, read the statement from FirstRand Bank to EE Publishers.
This leaves Absa as the only remaining South African commercial bank that has not yet withdrawn from funding the Thabametsi and Khanyisa projects.
Globally, banks are coming under increased pressure from society, shareholders and some national governments regarding funding of new coal-fired power stations, as well as the management and disclosure of their climate risks and opportunities.
South African banks appear to be falling in line with new Organisation for Economic Co-operation and Development (OECD) country protocols. These prohibit the construction of all new coal-fired power plants other than those using the latest ultra-supercritical (USC) steam generating technology, which provides increased efficiency (typically greater than 45%) and lower CO 2 emissions.
The Thabametsi and Khanyisa plants, on the other hand, would use circulating fluidised bed (CFB) boiler technology operating at subcritical pressure and temperature, giving efficiencies of about 32%.
In South Africa, a major study indicates that over their 30-year life, Thabametsi and Khanyisa would emit some 200-million tons of carbon dioxide equivalent (CO 2 e), putting their emissions per kWh generated among the very worst and oldest of Eskom’s non-compliant coal-fired power plants.
The study shows that this would negate most of the government’s emission mitigation plans, including the vast majority of the expected emissions savings of the entire energy efficiency strategy to 2050.
In South Africa, civil society opposition to new coal power projects has been led by environmental activist NGOs including Earthlife Africa, groundWork and the Centre for Environmental Rights (CER) in their Life After Coal Campaign.
These NGOs have welcomed FirstRand’s decision not to fund the proposed IPP coal-fired power station, Thabametsi, and Standard Bank and Nedbank’s decision not to provide financing for Thabametsi or Khanyisa.
“Both projects are currently the subject of litigation and have been shown to be unnecessary and dirty — among the highest GHG-emission intensive plants in the world, with attendant impacts on human health and wellbeing. They are also staggeringly expensive”, said Robyn Hugo, head of the CER’s pollution and climate change programme.
“It’s high time that banks acknowledge that funding these projects runs completely contrary to the climate and sustainability commitments they have made. These developments are in line with international trends which recognise that the reputational and other costs of being in business with coal are unsustainable”, she said.
With the above in mind, one can only wonder if and when Absa will follow Standard Bank, Nedbank and FirstRand Bank’s lead, and withdraw from funding Thabametsi and Khanyisa too, and whether the Department of Energy’s new-coal IPP programme will be stillborn. DM
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From tech darling to the brink in just four years. Ofo went through a billion dollars, left our streets littered with bikes and their staff without salaries. They are getting a much deserved exit. Bye Ofo!
Driven by sheer stupidity and greed, we saw the kind of investment frenzy where investors were on a freefall. Like a spoilt brat, Ofo grew too big for its shoes at breakneck speed. Now, having spent a billion dollars almost foolishly in our opinion, Ofo is laying off staff without notice just to get by.
Since the latter part of 2018, several reports of Singapore’s Ofo rising debts and immediate staff layoffs made headlines. The previously multi-billion bike-sharing firm left its headquarters in the city-state with almost no warning.
Recently, a few days waiting for the Lunar New Year celebration, Ofo made another drastic move of laying off its key Singapore operations personnel.
For this week alone, about 10 Ofo workers were informed that their services are no longer needed by the company and their employment ends by January 31. The notification was done in a rush and they would not be getting any severance pay or equivalent to one month’s salary as stipulated in their employment contracts.
The worse about the situation was that they were not provided at least a month’s notice to look for jobs. No valid reason was cited to justify the lay-off.
The Singaporean government has pressured Ofo regarding the imposed guidelines like indiscriminate bike parking and bills’ payments, fines, and refunds. The country’s Land Transport Authority has given an ultimatum for the bike-sharing company to submit all the requirements on or before February 13. Otherwise, Ofo’s license to operate in Singapore will be revoked.
Also, the company has to pay the vendors over S$700,000 (US$519,000) for delivered logistics services.
Ofo’s operations have expanded to different countries after its aggressive move beyond China. These went overseas such as Australia, Germany, Japan, United States, India, Israel, and South Korea. Singapore was probably the firm’s next failed attempt abroad.
In China, Ofo, as a cash-strapped firm, struggles to provide the demands for returning deposit refunds. During the end of 2018, about 11.7 million of Ofo’s Chinese clients were claiming for refunds. The total amount was over RMB 1.16 billion (US$168 million).
Initially, Ofo was a great success and part of the bike-sharing boom in recent years worldwide. In China, there were about six major bike-sharing companies competing at each other. In 2015, another Chinese bike-sharing start-up Mobike was introduced. It was valued at over US$1 billion and got an investment such as tech giant Tencent.
When asked what went wrong? Dai Wei, Ofo founder, and chief executive, cited in an internal company meeting in Beijing in November 2018 that he has made ‘some wrong decisions’ in the past. These included the testing periods for the company, including some lawsuits by bike suppliers for nonpayment of bills.
http://theindependent.sg/ofo-pink-slipped-staff-without-compensation/
Indonesian insurance rules that come into effect on February 1 are causing huge coal supply backlogs, with dozens of ships held up outside ports unable to load as authorities start checking to see if vessels are in compliance with new policy.
Exporters of coal and palm oil must use local insurers from Feb 1, and local shipping companies from May 2020.
There were not enough surveyors to handle the fleet of ships and insurers and port authorities were taking time to issue new documents.
Brazilian miner Vale needs to change its behavior, cooperate more with authorities and be more transparent after a deadly dam collapse at one of its mines that likely killed more than 300 people, Brazil’s solicitor general said on Saturday.
Rescue workers search for victims of a collapsed tailings dam owned by Brazilian mining company Vale SA, in Brumadinho, Brazil February 2, 2019. REUTERS/Adriano Machado
Speaking with reporters in the town of Brumadinho, near Vale’s Corrego do Feijao mine that collapsed late last month, André Mendonça added that Vale’s actions had not improved since another deadly tailings dam collapse in 2015, the Samarco project that it joint-owned with BHP Billiton.
“Firstly, we need a change of behavior. There has been a behavior of resistance to complying with obligations and we need effective cooperation, not only in words, but in gestures, in acts, that demonstrate responsibility for what happened,” said Mendonça.
“We need to have an effective assumption by Vale of its responsibility for the event ... So, we expect effective, quick responses from Vale regarding the disaster.”
In a later statement, the solicitor general’s office said all of the costs associated with tragedy incurred by the federal government would be charged to Vale.
With 121 people confirmed dead and another 226 still missing, according to the latest tally on Saturday, the Brumadinho dam burst could be Brazil’s deadliest mine disaster.
The disaster poses a headache for the new government of far-right President Jair Bolsonaro, whose new business-friendly administration must juggle public anger over the tragedy and its own desire to ease mining and environmental regulations to kick-start growth.
Hildebrando Neto, Minas Gerais’ deputy minister for environmental regulations, told Reuters that all evidence suggests the burst was caused by liquefaction, whereby a solid material such as sand loses strength and stiffness and behaves more like a liquid.
Neto said liquefaction caused the 2015 collapse of the Samarco dam, which led to the deaths of 19 people.
Major Brazilian TV outlets obtained dramatic security camera video showing the outer wall of the dam collapsing and an avalanche of mud crushing trees, houses and cars in its path. Closeups replayed throughout the day showed cars and people scrambling unsuccessfully to escape the torrent.
Mendonça highlighted concern that Vale is not complying with obligations applied after the Samarco tragedy. He said compensation payments, as well as greater transparency and judicial compliance, have not been met.
In a statement, Vale said it had been cooperating with authorities, and “providing all support to the population and the families of those affected.”
Asked if members of Vale’s executive board could be arrested, Mendonça said “no hypothesis can be ruled out.”
German union IG Metall said on Friday it would recommend that workers in the iron and steel industry in the northwest of the country hold warning strikes next week, after it walked out of a third round of wage talks saying managers offered nothing new.
Knut Giesler, the union chief for North Rhine-Westphalia state, broke off the latest round of negotiations after just 15 minutes.
Warning strikes tend to be brief, lasting a few hours or a day. The union said it would propose a series of strikes to its wage commission on Saturday but gave no details of which companies would be targeted next week or when.
The steel employers’ association said the behavior of Germany’s biggest union in the negotiations was disappointing and “not constructive.”
IG Metall said in December it was seeking a 6 percent wage hike for the 72,000 steel industry employees in the northwest region, possibly setting a benchmark for millions of workers in Europe’s largest economy.
The union, which represents 3.9 million people in the metal working and electrical industries, also wants workers to get a 1,800 euro ($2,063) holiday bonus.
Andreas Goss, head of the employers’ group, said the two sides remained at odds over the bonus and over the terms for taking time off in lieu of the bonus.
The next round of talks is scheduled for Feb. 18.
Fortescue Metals Group has enjoyed a demand surge as Chinese steel mills embrace its new, higher iron content mix with customers signing new deals after trialling the product.
The higher iron content ore is a key plank of the mining giant’s strategy, with product attracting higher prices than lower iron grades.
“Our West Pilbara Fines introduction has gone very smoothly, there’s been widespread support for the product and we have healthy sales orders,” Fortescue director of operations Greg Lilleyman said following a visit to Chinese mill operators in January.
Mr Lilleyman was speaking on the release of Fortescue’s December Quarterly report, which revealed that Fortescue had increased its estimate for shipments of the new product to between 8-10 million tonnes in fiscal 2019, up from earlier estimates of 5-10 million tonnes.
Over the preceding 12-18 months Fortescue had encountered deep discounts on its lower iron content, relative to a widely accepted industry benchmark for ores with a 62 per cent iron content.
Historically, much of Fortescue’s ores have had an iron content of about 58.5 per cent. The first cargo of its new product, shipped to China in December, had an iron grade of 60.1 per cent.
“We knew that there was demand and we’re seeing that demand come through,” said Fortescue chief executive officer Elizabeth Gaines.
The performance saw Fortescue’s share price life 4.24 per cent to $5.65. The miner’s stock has risen from $4.69 a week ago.
In the long term production of Fortescue’s West Pilbara Fines product will be underpinned by its new $US1.28 billion ($1.69 billion) Eliwana mine, which was confirmed by the miner last year.
Mr Lilleyman said changes in the Chinese steel market were working in Fortescue’s favour.
“Without exception they (steel makers) all talked about declining steel profitability, particularly as it (was) pronounced late last year,” he said.
“And therefore they have a greater focus on input costs over productivity. As a result, there’s much greater interest and demand for our lower iron products. Which is translating into a narrowing of the price spread between higher and lower iron products.”
Mr Lilleyman attributed the rise in realised prices in the quarter to a combination of the narrowing in the price spread between higher and lower iron content ores, and the impact of two other iron ore products including Fortescue’s new West Pilbara Fines ore.
Ms Gaines said the miner had recorded a strong December quarter, where it had decreased its cost of production to $US13.02 per wet metric tonne, and had lifted shipments by six per cent to 42.5 million tonnes. Fortescue’s average realised price for the quarter rose seven per cent to $US48 per dry metric tonne.
Ms Gaines said Fortescue was on a “very strong” financial footing, and its balance sheet had been comprehensively restructured.
https://www.hellenicshippingnews.com/china-steel-mills-back-fortescues-new-iron-ore-blend/
US met coal supplies have tightened in high-vol A and high-vol B grades as production dropped off in the fourth quarter, limiting spot opportunities currently, according to suppliers and traders who met in Miami last week.
US met coal export prices relative to the TSI Premium HCC benchmark for Australian FOB exports have risen in January, with the S&P Global Platts high-vol A assessment at around parity with TSI PHCC on average last month, up from just below 95% of TSI in December. High-vol B rose to 83% to the TSI PHCC benchmark in January, from 76% in December.
US East Coast low-vol may be better balanced on strong regional demand and as the Pinnacle mine closure helped offset a reduction in demand from China due to tariffs on US coals.
Fewer US blends were being sold into tariff-hit Turkey since the second half of 2018, sources said, which led to more blend material, especially in Central and Northern Appalachia, seeking other markets.
Some of the high-vol output declines were expected to be short term but the overall market has been left tighter as Ramaco has recovered this quarter from a silo outage, which hit processed coal volumes since November.
Ramaco was expected to be running processing of raw coal at 80% at Elk Creek since it installed a temporary system in January, under previously released company plans.
Other miners including Blackhawk Mining and Arch Coal reporting falling output at related mines to MSHA were still facing challenges.
The coal industry remains working to minimize headwinds, including equipment availability and technical challenges worsened by declining investment in coal services, and adapting to any sudden changes in geology at remaining reserves.
Since bankruptcies hit the US sector, met coal mining output recovered slowly from 2015, with upside limited by structural barriers such as availability and maintenance rates on equipment, and hiring qualified personnel.
Blackhawk's Panther mining complex was planned to recover in volumes this quarter from a sharp drop in output during the fourth quarter at the American Eagle mine, according to sources close to the matter, citing MSHA data.
That should help recover supplies into strong high-vol B contract demand, which saw growth in 2019 contract volumes.
Buyers plan to increase contract volumes for high-vol B for plants in Europe and Brazil, where some quantities were previously procured under shorter-term tenders and spot inquiry, sources said.
US domestic demand for high-vol A and other better quality high-vols and mid-vols was being supported by coke shortages and steel rates, sources said.
Along with stronger Indian purchasing for US mid-vol blend in Q1 reported earlier, a 20% decline in Q4 output at Arch Coal's Leer Mine and with the outage at Ramaco's Elk Creek limited quantities for prompt spot export sales. Arch made a longwall mining section change at Leer in Q4, the company said.
With limited spot offers and steady demand, tradeable prices for high-vol A are largely affected by values of alternative premium low-vol and mid-vol delivered to the Atlantic.
"Traditionally when premium low-vol or mid-vol is not available or rise in price, Atlantic buyers tend to buy more high-vol A," a miner said.
Japan may be set to continue to buy more US coals, in line with the rise in US met coal exports to Asia's biggest buyer in 2018, according to a buyer. US met coal shipments to Japan were running at around a 20% increase in 2018, based on latest US customs data.
Contract volumes to one group were indicated to be steady in 2019-2020 and at higher shipment levels than in 2017-2018.
National Steel Policy 2017 provides preference to domestically manufactured iron and steel
The total steel production in the country has increased from 88.98 million tonnes (MT) in 2014-15 to 103.13 mt in 2017-18. The Minister of State for Steel, Vishnu Deo Sai, informed this in Lok Sabha today. The Government has notified the National Steel Policy, 2017 and the Policy for Providing Preference to Domestically Manufactured Iron and Steel (DMI&SP) in Government procurement, which create facilitative environment to improve domestic production and consumption of steel.
With a view to provide relief to the domestic industry, the Government of India took the following measures:
* Increased customs duty on steel in two phases-in June 2015 and August 2015, by 2.5% each.
* Minimum Import Price (MIP) imposed on specified steel products in February 2016. MIP has since expired in February 2017.
* Imposed 20% Safeguard Duty on Hot Rolled Coils, provisionally in September 2015 and finally notifying it in August 2016.
* Imposed Safeguard Duty on Hot Rolled not in Coils, provisionally in August and finally in November 2016.
* Imposed Anti dumping measures for HR Coils provisionally in August 2016 and finally notified in May 2017.
* Imposed Anti dumping measures for CR Coils provisionally in August 2016 and finally notified in May 2017.
* Imposed Anti dumping measures for Wire rods provisionally in September 2016 and finally notified in October 2017.
* Imposed Anti-dumping duties for Colour Coated Steel provisionally in January 2017 and final notification issued in October 2017.
* Sunset review of SS Cold Rolled 600-1250mm wherein duties extended upto 2020. On China, additional Countervailing Duty (CVD) at 18.95% for 5 years from September 2017.
* Imposed Anti dumping duties on SS Hot Rolled products in March 2014 valid upto 2020. On China, additional CVD at 18.95% for 5 years from September 2017.
Government of India has also issued Quality Control Orders namely Steel and Steel Products (Quality Control) Order, 2018 covering 47 carbon/alloy steel and 6 stainless steel products. The Quality Control Order prohibits manufacturing / import of sub-standard / seconds and defective products.
The Minister of State for Steel said India has not been much impacted by the tariff imposed by USA since India’s exports to the USA were just around 2.2% before the imposition of the tariff.
(Updates to add details, quotes, context)
MOSCOW, Feb 5 (Reuters) - Russian steelmaker Severstal said on Tuesday its core earnings rose 5.3 percent in the fourth quarter compared to the same period the previous year, supported by stronger profits at its coal and iron ore division.
Severstal, one of Russia’s largest steelmakers, said its earnings before interest, taxation, depreciation and amortisation (EBITDA) totalled $794 million in the fourth quarter. This was up from $754 million in the fourth quarter of 2017.
Quarter-on-quarter, EBITDA rose 3.4 percent, up from $768 million. Net profit rose to $578 million, up 27 percent quarter-on-quarter, while revenue rose 1.1 percent to $2.1 billion, Severstal said.
Net debt rose from $438 million in the third quarter to $1.23 billion in the fourth quarter, the company said. This primarily reflected a fall in cash balances after its fourth quarter dividend payout, it said.
“Although domestic steel demand is moderating, we expect world steel demand to remain at good levels in 2019, based on a strong global economy and continued limits on steel production and economic incentives in China,” Alexander Shevelev, chief executive of Severstal Management, said in a statement.
Shares in Severstal, traded in Moscow, were up 0.1 percent on the day.
Fourth quarter free cash flow fell 51.6 percent compared to the previous three months to $233 million, the company said, due to a jump in capital expenditure and net working capital accumulation at the end of the quarter.
In November, Severstal announced a string of investment projects and said it expected capital expenditure to rise to around $1.4 billion in 2019, from an average of $800 million annually in the previous 7 years.
The company confirmed this forecast on Monday, saying capital expenditure would be at $1.46 billion this year.
However, fourth quarter capital expenditure - at $224 million, Severstal said - came in below the expectations of analysts at BCS Global Markets.
“Lower than expected capital expenditure confirms our view that the company overestimates investments,” BCS analyst Oleg Petropavlovsky wrote in a note. (Reporting by Ekaterina Golubkova; Writing by Polina Ivanova; Editing by Christian Lowe)
https://af.reuters.com/article/commoditiesNews/idAFL5N2001AS
Brazilian miner Vale SA on Tuesday declared force majeure on some iron ore contracts after a court-ordered halt to a mine responsible for nearly 9 percent of its output following a dam burst which likely killed more than 300 people.
The force majeure on some iron ore and pellets sales contracts came after a court on Monday ordered it to stop using eight tailings dams, including one affecting production of about 30 million tonnes of iron ore output per year.
The force majeure is the latest sign of how the Jan. 25 disaster at the tailings dam at Vale’s Corrego do Feijao iron ore mine in Brazil’s mining heartland of Minas Gerais, which killed 142 people, with 194 still missing, is roiling the broader mining industry.
Iron ore prices have surged since the disaster, hitting a nearly two-year high on Monday.
The force majeure announcement came as questions swirl around whether more could have been done to prevent the Brumadinho disaster, Brazil’s deadliest ever.
A report Vale commissioned last year to look into the stability of the tailings dam certified it as sound but raised concerns over its drainage and monitoring systems.
The report by German-based TÜV SÜD, reviewed by Reuters on Tuesday and marked as last updated in August 2018, made a variety of recommendations aimed at improving the safety of the structure, It also said the dam adhered to the minimum legal requirements for stability.
Among the issues identified were cracks in drainage channels, which were pictured in the report. The audit also recommended the installation of a new monitoring system able to pick up tiny movements in the soil.
LIQUEFACTION
Vale said in a statement it had followed the recommendations in the report, which it described as “routine.”
Vale shares closed almost stable on Tuesday, at 44.68 reais, after having lost 15 percent this month.
The report appeared at odds with a statement from TÜV SÜD the day after the spill, which said “based on our current state of knowledge, no damages were found” during their inspection of the dam.
Issues with drainage could be crucial in investigations into the causes of the dam rupture, with a state environmental official telling Reuters that evidence suggested the burst was caused by liquefaction.
Liquefaction is a process whereby solid material such as sand loses strength and stiffness, behaving more like a liquid.
It is a common cause for the collapse of upstream dams holding mining waste, known as tailings, because their walls are mostly built with dried tailings of sand and clay-like mud. Drainage issues can cause water to seep into the dried tailings, changing their consistency and stability.
“To increase dam safety regarding failure from liquefaction, it is recommended to adopt measures to reduce the possibility of a trigger,” TÜV SÜD said in its evaluation of the dam, recommending avoiding work that could cause an “overload” of the dam’s reservoir.
“The installation of seismological monitoring equipment is also recommended in the vicinity of the dam.”
TÜV SÜD did not respond to a request for comment.
A Canadian steel industry group said on Tuesday it would strongly oppose a petition filed by its U.S. counterpart urging anti-dumping duty on certain steel imports from Canada.
The Canadian Institute of Steel Construction (CISC) was responding to a petition filed by the American Institute of Steel Construction (AISC) asking for anti-dumping and countervailing duties on some fabricated structural steel from Canada, Mexico and China, alleging that the imports were hurting U.S. steel producers.
The petition was filed on Monday to the U.S. Department of Commerce and the U.S. International Trade Commission (USITC).
“AISC’s allegations that these products from Canada are unfairly traded and cause injury to U.S. producers of fabricated steel products are baseless,” Ed Whalen, chief executive officer of the CISC, said on Tuesday.
“The negative effects of the Section 232 steel tariffs are the more likely cause of injury for the U.S. downstream steel sector, not Canada.”
The USITC’s website on Tuesday showed that it was investigating these claims by AISC, listing the probe as “active.” Investigations do not always lead to new duties.
AISC could not be immediately reached for comment.
Salzgitter on Tuesday said its pre-tax profit could fall by nearly two thirds this year, pointing to cooling demand for steel amid increasing signs of a global economic slowdown.
Citing “gloomier sentiment and numerous economic and political uncertainties”, Salzgitter expects pre-tax profit of 125 million to 175 million euros ($143-$200 million) this year, down from a preliminary figure of 347 million in 2018.
Shares in the group, Germany’s second-largest steelmaker after Thyssenkrupp, fell as much as 10.8 percent hitting their lowest level since July 2016. They were down 9 percent at 1600 GMT.
JP Morgan analysts last month pointed to rising recession concerns for the steel sector, citing deteriorating investor sentiment and economic data and putting the chance of a global recession over the next 12 months at 43 percent.
Jefferies analysts said: “As the Euro steelmaker most exposed to short-term sales contracts ... Salzgitter’s disappointing FY19 guide clearly reflects recent metal spread compression sparked by weakening steel prices and surging iron ore.”
Salzgitter’s forecast for its 2019 pre-tax profit is significantly below an estimate of 286 million euros based on Refinitiv data.
The company said it expects 2019 sales of more than 9.5 billion euros, up from a preliminary 9.3 billion last year.
The group will release full preliminary results on Feb. 27.
Global trader Glencore said on Wednesday that production at two of its Australian coal operations has been affected by heavy rain that has caused flooding in northern parts of Queensland state.
“We have experienced short-term production impacts from heavy rain at our two most northerly coal sites, Collinsville and Newlands,” a Glencore spokesman said in a statement to Reuters.
It gave no further details.
Combined, the mines produced around 8 million tonnes of thermal and coking coal in 2017.
Major flooding has caused parts of Queensland to be declared disaster zones, resulting in two casualties and more than 1,100 evacuations, after authorities opened up dam gates following days of torrential rains that filled reservoirs to overflowing.
Glencore, which is also a major producer of copper and zinc in Australia, said “controlled operations” were continuing at its Queensland copper and zinc businesses in Townsville, Mount Isa and Cloncurry.
Russian miner and steel group Severstal said iron ore pellet prices rose in the fourth quarter, with output falling to 2.94 million mt from 3.3 million mt a year earlier.
Severstal iron ore pellet sales prices averaged $101/mt in Q4, compared with $73/mt in Q4 2017, and up around 10% from Q3 2018, according to a company presentation. Pellet prices averaged $90/mt in 2018, up from $79/mt in 2017 and $49/mt in 2016.
The S&P Global Platts Atlantic contract blast furnace pellet price in 2018 saw monthly assessments average around $114/dry mt on an FOB Tubarao, Brazil, basis, up from around $15/dmt FOB Tubarao in 2017. The assessment uses trailing one-month averages for IODEX 62% fines, and spot Capesize rates for the prevailing period to netback from the China-delivered benchmark to Brazil.
The Karelsky Okatysh unit’s pellet sales rose from 2.55 million mt in Q3 2018, supported by higher production volumes at the northwest Russian mine, and a stock selloff last quarter, the company said in a statement.
The higher pellet sales volumes were supported by greater sales of goods in transit booked during the period.
Severstal’s coking coal sales in 2018 were 3.37 million mt, up 2% from 2017, despite a soft Q3 2018. Vorkutaugol coking coal concentrate prices averaged $115/mt FCA northwest Russia in Q4, and $125/mt in 2018, it said.
The company expanded sales of coal to external customers during the quarter, based on favorable pricing conditions, with internal sales making up 83% of total sales volume, the company added.
Source: Platts
https://www.hellenicshippingnews.com/russias-severstal-iron-ore-pellet-prices-rise-in-q4/
Moneycontrol News
Higher sales in the domestic market couldn't make up for the steep fall in exports, as steel major JSW Steel on Thursday reported a 9.96 percent fall in consolidated net profit in the third quarter of the financial year.
Its net profit stood at Rs 1,603 crore for the October-December quarter of 2018-19, compared to Rs 1,774 crore in the year-ago period.
"Exports declined by 70 percent in the quarter, and accounted for only 10 percent of the total sales," said Seshagiri Rao, Jt Managing Director and Group CFO of JSW Steel.
Total sales, thus, was down 7 percent from a year ago, at 3.68 million tons.
The country's largest steelmaker increased its total income by 11 percent to Rs 20,355 crore from Rs 18,306 crore, a year ago.
"Surplus steel, waning demand in China, tight financial condition and escalating trade wars have led to softening of demand and prices," added Rao, in an interaction with media post the results announcements.
Total expenses too increased almost 11 percent to Rs 17,916 crore during the December quarter of 2018 as against Rs 16,188 crore in the corresponding period of the previous fiscal.
On the domestic front though, JSW Steel increased its market share to 13.7 percent in the third quarter, up by 0.8 percent a year ago, with its sales in the home market increasing by 15 percent year-on-year.
Shares of the company on February 6 ended 2.06 percent up at Rs 279.30 a piece on the BSE.
Outlook
The slowing export will continue to cloud over the company's sales for the rest of the financial year.
JSW Steel, in its guidance, said that it will fall short of its annual sales guidance of 16 million tons, by 2 to 3 percent.
But add Rao was optimistic of the realisations holding strong. A cut in supply of iron ore in the international market is expected to push up the steel prices.
At the same time, JSW Steel may not have to pay as much for the raw material, thanks to a supply glut in the domestic iron ore industry.
It also helps that production in China has been slowing down since November last year, reducing prospects of over supply in the domestic market, and hopefully lower imports into India.
But the risk of imports will continue. In the third quarter, steel imports had increased by nearly 8 percent, even as overall exports from India fell 40 percent. Steel consumption grew by 8.1 percent, said a release by JSW Steel.
The company is hoping that the consumption stimulus of Rs 1 lakh crore, which was announced in the Union Budget, will help drive steel demand in the domestic market.
The Budget, announced on February 1, included monetary support for farmers and pension for workers in the unorganised segment.
Vale SA, the world’s largest iron ore miner, plans to invest some 1.5 billion reais ($400 million) starting in 2020 to reduce its reliance on tailings dams, it said late on Tuesday, after one collapsed last month, likely killing hundreds.
The dam at the Feijao do Corrego mine burst on Jan. 25 in the Brazilian town of Brumadinho in what is likely the country’s most deadly mining disaster ever. Rescuers have found 142 bodies and almost 200 people are still missing.
Vale said its plan to reduce its reliance on giant dams to store the muddy detritus from mining, known as tailings, would boost to 70 percent by 2023 the portion of the leftover material that is dried out rather than stored wet.
The company also said it would spend about $70 million on safety and maintenance measures for existing tailings dams in 2019, representing a 180 percent increase from 2015. That year a Vale joint venture was responsible for another deadly dam spill that killed 19 people and polluted a major river.
A Vale spokeswoman said that both the 2019 investment in dam management and the plan to produce more dry tailings had already been budgeted before the Brumadinho disaster but not made public.
In December, Vale agreed to pay $500 million for New Steel, a company that owns patents in 56 countries for a dry processing method known as Fines Dry Magnetic Separation.
In 2009, one Vale executive identified concerns about the tailings dams and discussed the possibility of making building material from tailings, including bricks, as one measure to reduce the hundreds of thousands of tonnes of wet tailings, Reuters reported last week. Whether the company followed any of his recommendations at the time is unclear.
Vale has come under intense public pressure since the Jan. 25 dam burst, with some politicians and prosecutors calling for criminal prosecution and a management shakeup.
A court-ordered halt to production at several of its dams on Monday froze production at its largest mine in Brazil’s mining heartland of Minas Gerais, responsible for nearly 9 percent of the company’s output.
The Brazilian state of Minas Gerais canceled Vale SA’s license to operate a dam at one of its largest mines, the company said on Wednesday, following the collapse of another dam in the state that killed an estimated 300 people.
Vale has come under intense public pressure since the Jan. 25 dam burst, with some politicians and prosecutors calling for criminal prosecution and a management shakeup, especially since it happened less than four years after another fatal dam burst in Minas Gerais.
Vale shares on Sao Paulo’s Bovespa exchange fell 4.9 percent to a seven-day low of 42.46 on Wednesday, while its U.S. traded ADRS slumped 6.2 percent.
The state canceled Vale’s license for Laranjeiras dam. It had been used in the operation of the Brucutu mine, which had already been suspended by a court order, freezing nearly 9 percent of the company’s output.
Vale, which was already trying to appeal the court order, said it would also appeal the license cancellation.
Minas Gerais also canceled Vale’s license to operate its Jangada mine, which has been paralyzed since the dam close to the Córrego do Feijão mine burst in the state, killing at least 150 people. Another 182 people are still missing from what is possibly Brazil’s most deadly mining disaster.
The cut in output from Brucutu forced Vale to declare force majeure in iron ore and pellets contracts on Tuesday.
In the latest report to raise questions about whether warning signals were missed ahead of the mud avalanche which felled buildings and trees in the town of Brumadinho, Globo TV reported that Vale had been made aware of problems with sensors designed to monitor the structure.
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The report cited a deposition by an engineer for German inspection firm TÜV SÜD, whose job it was to monitor the dam’s safety. Both Vale and TÜV SÜD declined to comment on the report.
Separately, the German firm said in a statement that it had hired two external law firms to conduct an independent probe into its role in the dam collapse. Two of its employees were arrested following the accident but were released on Tuesday.
Vale, which co-owned another dam whose 2015 collapse killed 19 people and polluted a major river, said on Tuesday it would invest some 1.5 billion reais ($400 million) starting in 2020 to reduce its reliance on giant dams to store the muddy detritus from mining, known as tailings.
It aims to boost the portion of the waste material that is dried rather than stored wet to 70 percent by 2023.
The company also said it would spend about $70 million on safety and maintenance at existing tailings dams in 2019, representing a 180-percent jump from 2015.
In December, Vale agreed to pay $500 million for New Steel, a company that owns patents in 56 countries for a dry processing method known as Fines Dry Magnetic Separation.
In 2009, one Vale executive identified concerns about the tailings dams and discussed the possibility of making building material from tailings, including bricks, in a bid to trim the vast amounts of wet tailings, Reuters reported last week. It was not clear whether the company followed any of his recommendations at the time.
ArcelorMittal, the world’s largest steelmaker, on Thursday forecast a slight expansion of global steel demand in 2019 after a healthy market drove its earnings to their highest level in a decade last year.
The company said it expected world steel demand to grow by between 0.5 and 1 percent this year after an increase of 2.8 percent in 2018.
Demand, it said, would improve in all regions except China, the world’s biggest producer and consumer of steel, where ArcelorMittal has a minimal presence.
The most rapidly expanding market would again be Brazil, with a 3.5-4.5 percent growth this year from 7.3 percent in 2018. Steel demand in ArcelorMittal’s main markets, Europe and the United States, would grow by respectively 0.5-1.0 percent and 0.5-1.5 percent, lower than last year.
“Although the issue of global overcapacity persists and there are well publicised macro-economic risks, we expect further, moderate global steel demand growth this year,” Chief Executive Lakshmi Mittal said in a statement.
“Having considerably strengthened the company in recent years, we are in a strong position to generate healthy levels of free cash and prosper through the cycle.”
The company said it expected its steel shipments would increase, boosted by operational improvements. Capital expenditure would increase to $4.3 billion from $3.3 billion in 2018.
ArcelorMittal is investing in projects in Mexico and Brazil. It has also bought Italy’s Ilva, Europe’s largest capacity steel plant, and is close to completing the acquisition of Essar Steel, a deal that would see it entering the high-growth Indian market.
The company, which skipped shareholder payouts in 2015 and 2016, doubled its proposed dividend to $0.20 per share, more than the average $0.12 forecast in a Reuters poll.
Net debt at the end of 2018 was at $10.2 billion, slightly down from the $10.5 billion at the end of the third quarter. ArcelorMittal is seeking to reduce it to below $6 billion, with a return to an investment grade rating a priority.
The company reported fourth-quarter core profit (EBITDA) of $1.95 billion, a 9 percent decline from a year earlier. That was broadly in line with the company-compiled consensus of $1.96 billion from a group of about 20 brokers.
For the full year the figure was $10.27 billion.
A coal train derailed on eastern Australia's Hunter Valley coal exports rail network early Wednesday morning local time, forcing the suspension of operations between Baerami and Ulan, with the line expected to remain closed until early next week, the Australian Rail Track Corporation said in an email Thursday.
"Approximately 1.7 kilometers of track will need to be repaired including replacement of sleepers and rail. The current forecast for services to resume is early next week, subject to all works going well," an ARTC spokesman said.
Six wagons from the coal train are being recovered Thursday, which will allow for track and signaling repairs to begin, she said.
The incident took place on the Ulan line at around 3:30 am Wednesday (1630 GMT Tuesday). There were no injuries reported, she said.
The Hunter Valley coal rail network connects to the Port of Newcastle in New South Wales state, where coal is exported via the Port Waratah Coal Services terminals as well as the Newcastle Coal Infrastructure Group shipment facility.
Coal stocks at PWCS stood at 1.84 million mt as of midnight Wednesday with a vessel queue of five ships, according to data from the Hunter Valley Coal Chain Coordinator.
For the week ended February 3, there was 3.28 million mt of coal delivered to both PWCS and NCIG via rail, HVCCC said. Prior to the rail issue, HVCCC said February nominations at PWCS were 7.8 million mt and it was expected to have eight vessels queuing by the end of the month.
Local media, the Newcastle Herald, reported that the six wagons were laden with coal and returning from the Moolarben coal mine. It was a Pacific National train, it reported.
Pacific National, the operator of the derailed train was not available for immediate comment.
Finland’s Outokumpu warned on Thursday that first-quarter profit would weaken as high distributor inventory levels pressure the stainless steel market, sending its shares sharply lower.
Shares in Outokumpu dropped 9.3 percent to 3.64 euros by 0900 GMT, making it the biggest faller on the OMX Helsinki 25 Index. The overall index was up 0.4 percent.
In the fourth quarter the firm’s adjusted earnings before interest, taxes, depreciation and amortisation (EBITDA) rose 9 percent to 89 million euros, in line with analysts’ average forecast of 89.2 million from a Reuters survey.
However the company forecast that EBITDA in the January to March period would be below 89 million euros, sharply down from 133 million a year earlier.
Outokumpu said the Americas business would continue to report weak results after posting an underlying loss of 22 million euros due to decreasing deliveries and prices.
“2018 marked an exceptional year for the European steel industry. The unforeseen trade disruption caused by the U.S. steel tariffs led to a surge of low-cost imports into Europe and to heavy price pressure that put a strain on the entire European steel industry,” chief executive Roeland Baan said in a statement.
“The EU’s permanent safeguards that are now in force are expected to stabilize the import situation in Europe during 2019,” Baan said.
Outokumpu’s largest competitors include China’s Tsingshan and TISCO, Spain’s Acerinox and Luxembourg-based Aperam . Shares in Aperam were down 1.6 percent at 28.04 euros and Acerinox was down 2.7 percent at 9.38 euros.
The Indonesian government has set the coal benchmark price (HBA) for February at $91.8 per tonne, slightly lower compared to $92.4 per tonne in January, the mining ministry said in a statement on Wednesday
* The benchmark price fell for a sixth consecutive month in February due to import restriction in China and India, the ministry said
* “The policy to utilise domestic coal output in both countries had some impacts on the lower coal benchmark price this month,” the ministry spokesman Agung Pribadi said in the statement
* The HBA is a monthly average of the Argus-Indonesia Coal Index (ICI-1), the Platts Kalimantan 5,900 assessment, the Newcastle Export Index and the globalCOAL Newcastle index from the previous month
https://www.hellenicshippingnews.com/indonesia-sets-coal-benchmark-price-hba-at-91-8-t-for-february/
A total of 6.45 million mt of coal was exported from the Port of Gladstone in Queensland, Australia, in January, up 37% year on year and 4% month on month, as volumes to Japan surged and shipments to India eased off, data from the Gladstone Ports Corporation showed Thursday.
After surging in 2018, Gladstone's coal exports to India started the new year on a slightly lower note at 1.42 million mt, down from 1.43 million mt in January last year and a drop of 12% from December.
While it is the first time in five months that exports from Gladstone to India have fallen below the 1.6 million mt mark after expansions in the Indian steel sector lifted volumes to as high as 1.95 million mt in May last year and 17.75 million mt in 2018 as a whole with a 48% year-on-year jump, the country's metallurgical coal imports are expected to continue rising again.
"India is forecast to overtake China as the world's largest importer of metallurgical coal in 2020, with India's imports forecast to grow steadily over the next two years, to reach 71 million mt in 2020," Australia's Department of Industry, Innovation and Science said in late December. That compares to an expected 67 million mt for China in 2020.
China-bound shipments remained depressed in January after a 23% year-on-year slide in 2018 to 9.94 million mt. The January total was 689,000 mt, which is up 62% year on year and down 42% month on month. The January volume is below the 2018 monthly average of 825,000 mt and well below the 1.08 million mt/month average in 2017, the data showed.
There's expected to be a slight softening in China's metallurgical coal imports over the next couple of years due to a moderation in the country's steel production as its economic growth slows.
Gladstone's exports are made up of approximately 70% metallurgical coal and 30% thermal, GPC says.
Japan-bound coal shipments from Gladstone rose to an eight-month high in January with 2.06 million mt, showing a 20% rise year on year and 44% increase from December, GPC said.
Volumes to South Korea were also firm at 1.18 million mt -- the highest in three months, up 70% year on year and 17% month on month, it said.
Although its volumes are small compared to Gladstone's other key export destinations, Taiwan saw a 17-month high with 331,000 mt in January, up 86% year on year and more than four times as much as the 80,000 mt shipped in December, the data showed.
India's 12 major government-owned ports handled 86.51 million mt of thermal coal over April 2018-January 2019, up 12% from the same period a year earlier, Indian Ports Association data released Tuesday showed.
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Coking coal shipments at the 12 ports rose 13% year on year to 47.82 million mt in the same period, the data showed.
Paradip port on the east coast handled the highest volume of thermal coal shipments over April-January at 26.71 million mt, up 14% on year.
Kolkata port also on east coast received the highest volume of coking coal shipments at 16.30 million mt, up 55% on year.
The 12 ports are Kolkata, Paradip, Visakhapatnam, Ennore, Chennai, VO Chidambaranar (Tuticorin), Cochin, New Mangalore, Mormugao, Mumbai, Jawaharlal Nehru Port Trust (JNPT) and Deendayal (Kandla).
Chennai and JNPT did not receive any coal over April-January.
Developers have lost a court appeal to build a coal mine in Australia’s Hunter Valley over its potentially “dire” environmental impact in the country’s first legal review of a coal mine project to hear evidence from a climate scientist.
In the landmark ruling, Justice Brian Preston on Friday denied the appeal on the Rocky Hill project in New South Wales state, citing an increase in greenhouse gas emissions, as well as uncertain economic benefits and adverse social and visual impacts.
The Rocky Hill project was developed by privately held Gloucester Resources, a unit of GRL Holdings Pty Ltd, which has the right to appeal to the New South Wales supreme court.
“Gloucester Resources Limited will assess the implications of today’s decision and consider its next steps,” it said in a statement.
Australia is the world’s biggest coal exporter and the fuel is its largest resources earner. Canberra last year scrapped plans for a national energy policy that aimed to cut carbon emissions as well as power prices in part due to opposition from coal supporters within its ranks.
In his ruling, the judge found that mine and associated greenhouse gas (GHG) emissions would add to the global total “at a time when what is now urgently needed, in order to meet generally agreed climate targets, is a rapid and deep decrease in GHG emissions.”
“In short, an open cut coal mine in this part of the Gloucester valley would be in the wrong place at the wrong time,” Preston found. “These dire consequences should be avoided.”
At the end of January the Organisation of Economic Cooperation and Development made waves in Australia when it said the country needed to cut emissions more sharply to meet its Paris Climate accord target as the country remained heavily dependent on coal-fired power.
But on Thursday a study published earlier on Friday by Australian National University (ANU) researchers found the country is adopting renewable energy faster per capita than the rest of the world. Rapid recent growth in wind and solar power has left it on track to meet Paris carbon emissions reductions targets well before 2030, it found.
The ruling was set to make developing new coal mines or expanding existing projects more challenging, said Shaw & Partners analyst Peter O’Connor.
“On first pass it doesn’t read well for the industry,” he said. “And it does indicate an ongoing and increased level of scrutiny of this industry, which is only likely to become greater.”
Shares in Australian-listed coal miners Whitehaven and New Hope, which both have coal projects on the drawing board, fell 3.5 and 2.2 percent respectively by 0446 GMT on Friday, in line with lower Australian thermal coal prices.
Whitehaven declined to comment on whether it expects any impact on its own development plans. New Hope officials couldn’t immediately be reached.
Brazilian authorities have closed a port terminal operated by miner Vale SA in Vitoria, in the southeastern state of Espirito Santo.
The municipality of Vitoria has fined the miner 35 million reais ($9.5 million) for throwing mining residues in the sea.
Vitoria Mayor Luciano Rezende said “pollution cannot be justified by tax revenue any more,” according to a statement sent by the government.
