OPEC’s central bank problem

OPEC and the world’s most powerful central banks are on a collision course. Higher crude prices could push the custodians of the global financial system into tightening monetary policy quicker than expected to protect their economies from unchecked inflation. But, a kneejerk reaction could sow the seeds of economic slowdown, oil demand destruction and another price crash.

Take the problem facing Mark Carney, governor of the Bank of England. Lower-than-expected inflation figures released this week give the impression fears over the impact of higher energy costs in the world’s sixth-largest economy have been overblown. Since 2016, when oil prices dipped below $30/b, gasoline prices have jumped by almost 30% to an average around 127 pence/liter at the pumps.

And it’s not just vehicle fuel adding to the daily cost of life for British consumers and businesses. The price of almost every form of energy required for modern life is on the rise. Wholesale gas price futures have increased by almost 60% since 2016 close to 60 p/Btu, in what traders have described the “Trump bump”.

A similar trend is visible in UK power markets. Forward electricity prices have risen 32% over the last 12 months, prompting the Big Six retailers to hike bills in April. For example, British Gas’ 5.5% increase is translating into an extra GBP60 per year for a typical dual fuel customer already shelling out GBP1,200 a year on gas and power.

In theory, this should translate into higher inflation. Don’t be fooled by figures released this week by the Office for National Statistics. The consumer price index unexpectedly falling to its lowest level in a year is likely to be a short-lived respite. Economic experts agree that inflation and the British economy will eventually succumb to the rising cost of energy this year, forcing the Bank of England’s hand on interest rates.

“The rise in oil prices comes with unfortunate timing,” said Tej Parikh, senior economist at the Institute of Directors. “Buoyed by fast-falling inflation, households were becoming increasingly confident about their finances, while businesses were recovering from high import prices. But for the summer months at least, we’re likely to see some continued upward pressure on domestic prices and therefore restraint in consumer spending.”

At some point the rising cost of fuel will hit demand as households cut back on discretionary spending to ensure the lights stay on. Demand destruction is OPEC’s big fear as it seeks to rebalance oil markets in its favour in the wake of the US shale revolution. Oil prices crashed in 2008 from a peak of $147/b as the global financial crisis hammered consumers.

The International Energy Agency has already slashed its forecast for growth in daily demand by 40,000 barrels to 1.4 million b/d this year. The Paris-based industry watchdog now expects consumption of just over 99 million b/d, compared with 100 million b/d this year forecast by S&P Global Platts Analytics.

“With geopolitical tensions pushing up oil prices, higher fuel costs have partly countered the downward effect of weaker currency passing out of the figures, as these costs represent a key outlay for consumers,” Parikh added.

OPEC’s first chance to respond could come this week when senior officials and Russia’s energy minister Alexander Novak meet on the sidelines of an economic conference in St. Petersburg to discuss if a change in strategy is required to fend off further blame.


Higher energy costs are also being felt across the Atlantic. Gasoline prices almost hitting $5 per gallon in one New York filling station this week made national headlines. Charles Schumer, the Senate Democratic Leader, seized on the opportunity to hold an impromptu news conference at a Capitol Hill pump station. Schumer has called on US President Donald Trump to put more pressure on his petro-dollar allies in the Middle East.

“It’s time for this president to stand up to OPEC,” Schumer told the gathered press. Although Trump has taken to Twitter to accuse the cartel of rigging oil prices his policies have arguably played into OPEC’s hands. Oil prices have spiked above $80/b since his executive decision to withdraw the US from international sanctions relief on Iran, the group’s third-largest producer.

Perhaps sniffing a political opportunity to wound Trump and tug at his grassroots support, Schumer and his Democrat colleagues wrote to the president urging him to dispatch Energy Secretary Rick Perry to read the riot act to OPEC in Vienna on June 22. The cartel is next scheduled to meet in the Austrian capitol to discuss strategy and whether to persist with 1.8 million b/d of cuts designed to rebalance the market. Some would say their mission has already been accomplished.

“The impact of rising fuel prices on our economy and on family budgets is significant and widespread,” wrote Schumer and his Democrat colleagues in the letter dated May 23. “According to a recent analysis by Goldman Sachs, the run up in oil prices will roughly cancel out the effects from tax reductions this year, with greatest impact on households that can least afford it,” it said.

Like the UK, higher fuel bills in America also mean inflation and a big problem for the world’s most important central banker, Federal Reserve Chair Jerome Powell. The Fed is expected to continue raising interest rates this year as it moves towards its 2% inflation target and that could have a big impact on the nation’s shale oil boom, which has provided an element of insulation against dependence on OPEC.

The US oil industry, which now pumps just under 11 million b/d of crude, is sensitive to higher borrowing costs because of the fragmented nature of production in the country’s shale fields. So called “Mom and Pop” drillers in the “Lower 48” are more dependent on debt and short-term loans to fund their daily operations. These tiny companies could be hardest hit by rate increases, unlike global oil majors with vast balance sheets to absorb the shocks.

“One of the aspects of the shale revolution is that the oil market I think is more open and more exposed to credit market flows now going forward than it was in the past because of the increase of this huge number of small, heavily geared, producers working with the Lower 48,” said Spencer Dale, group chief economist at BP and a former member of the Bank of England’s rate-setting Monetary Policy Committee, in a recent interview with S&P Global Platts.

It’s not just the likes of political opportunists such as Schumer, central bankers, or irate British motorists paying GBP70 to fill up their tanks, who are now pointing the finger at OPEC. India’s energy minister Dharmendra Pradhan spoke with his Saudi counterpart earlier this month about the havoc higher oil prices could cause in the fast-growing Indian economy. It’s time the cartel took notice.

The post OPEC’s central bank problem appeared first on The Barrel Blog.

Source: http://blogs.platts.com/2018/05/25/opec-central-bank-problem/


Kinder Morgan set to pull the plug on Canadian crude export pipeline

Ever since Canada’s Liberal government came to power in late 2015, the 525,000 b/d Northern Gateway and the 1.1 million b/d Energy East pipeline projects fell off the radar, while a final investment decision remains due on the 870,000 b/d Keystone XL pipeline, which received a fresh lease of life after US President Donald Trump resurrected it last year.

The clock is now ticking fast for the 590,000 b/d Trans Mountain Pipeline Expansion, for which developer Kinder Morgan has a set a self-imposed deadline of May 31 on whether to proceed with the estimated $5.6 billion investment.

The expectation is that Kinder will likely pull the plug, as all other options start thinning out.

The Houston-based midstream company has been pursuing the expansion project since 2012 and has also received full shipper commitment from nearly a dozen oil sands producers in Alberta and refiners in the US. But last month Kinder decided to stop further spending unless it had clarity on the way forward.

Its stance came after relentless opposition from stakeholders in British Columbia, particularly the provincial government, which has not spared any efforts to come in the way of shovels being put in the ground thus summer.

Be it court cases or the announcement of an 18-month study to determine the environmental impact of a likely spill from the existing Trans Mountain pipeline, the ostensible plan of the British Columbia government was to delay start of construction, which in turn would drive up project costs and deliver its desired goal of Kinder abandoning the project.

Such actions irked neighbor Alberta, where the provincial government has been banking on the Trans Mountain Expansion to ensure uninterrupted growth of its multibillion-dollar oil sands industry.
Dwindling pipeline takeaway capacity from Alberta has resulted in producer’s dealing with deep price discounts for its Western Canadian Select (WCS) grade for the past six months.

For its part, Alberta reacted by enacting a bill in the provincial legislature in mid-May giving it the right to stop the flow of crude and refined products on the 300,000 b/d Trans Mountain line.

It is still not clear when and to what extent Alberta will turn off the taps on that line, but a prime aim of that legislation is to use it as a carrot and stick to ensure the British Columbia government either withdraws or at least considerably tapers down opposition to Kinder’s pipeline expansion plans.


Stopping crude flows on the line will cause a steep hike in gasoline prices in Lower Midland and Metro Vancouver – British Columbia’s two prime urban areas – that could result in street protests during the summer driving season.

The ongoing feud between Alberta and British Columbia will not in any way help Kinder to take a decision by its May 31 deadline.

Rather the scenario has taken a new turn with the federal government announcing May 16 that it will underwrite ‘political risks’ associated with the planned investment by Kinder Morgan.

“As a government we need to ensure the rule of law is respected and investors have the certainty needed to complete the Trans Mountain Expansion Project,” Canadian Finance Minister Bill Morneau told reporters May 16 in Ottawa.

Instead of taking a hard stance, like introducing a bill in Parliament making it mandatory for the British Columbia government to adhere to the Constitutional rights of a the federal government, Ottawa’s offer failed to have the desired impact.

“We are not yet in alignment and will not negotiate in public,” Kinder CEO Steve Kean reiterated in just a few hours in an apparent overture to Finance Minister Morneau’s offer.

In the world of insurance, intangible elements like political risks are often left open to interpretation and as a midstream player that has the expertise to create value with shareholder’s money, Kinder will exercise extreme caution and not be swayed by any government assurances.

Labeling the project as one that continues to face “exceptional political risk,” Kean said a private company cannot “resolve differences between governments.”

Ever since 2013 when it first filed an application with the Canadian regulator, National Energy Board, Kinder has spent about $900 million going through the regulatory process and also acquiring long-lead equipment like line pipe, valves and pump stations to guard against inflation and keep costs under control.

The Canadian parliament will have another week before its goes into summer recess and along with it any chances on a bill that will make it mandatory for British Columbia to adhere to any federal decisions.

Kinder has done more than its fair share to expand the pipeline that’s still underpinned by shipper interest. But looking ahead, it will turn attention to its shareholders and guard their interest first.

The post Kinder Morgan set to pull the plug on Canadian crude export pipeline appeared first on The Barrel Blog.

Source: http://blogs.platts.com/2018/05/25/kinder-morgan-canadian-crude-export-pipeline/

Summer peakloads could put stress on some US power markets as heat pushes up demand

Memorial Day Weekend is upon us, and with it the unofficial start of summer in the US.

Power markets have been prepping for the hot weather over past several weeks, with stakeholders studying the summer outlooks of grid operators and reliability coordinators.

Summers — and winters — are always a busy time for power markets as demand typically increases, while prices can soar.

For most of the US, summer peakloads are expected to be below last year’s forecasts, but above 2017 peaks.

It could get interesting in a couple of regions this summer as air conditioning use pushes up demand.

In Texas, a slew of recent generation retirements has dragged down the generation reserve margin to below target level. In turn, wholesale power markets have seen ERCOT summer monthly packages jump to levels more than double where they were at the start of the year, with most zones hitting near $220/MWh.

And forward markets were not alone in seeing premiums.

Heat spells have been driving up demand this month, and real-time prices have risen to above $1,000/MWh at times.

Earlier this year, a cold spell sent ERCOT real-time prices soaring to the grid operator’s price cap of $9,000/MWh for the first time in history.

Will history be made this summer? Expect all eyes to be on Texas as summer heats up.

Out West, the California ISO issued its summer outlook earlier this month that said because of low hydro generation levels and generation retirements it may have to issue a Stage 2 emergency this summer, something not seen for over a decade.

Complicating the picture are issues involving natural gas storage and maintenance in Southern California.

The possibility of a stage 2 emergency and natural gas problems has attracted the attention of energy regulators, who said they were “very concerned” about reliability.

California came awfully close to its all-time peak record last summer, with demand topping out over 50 GW, something also not seen in over a decade.

In past years when hydro has been depressed because of drought, California has caught a break with demand staying down, while solar and other renewables helped.

The markets will have to wait and see what history holds in store for the Golden State in 2018.

For more about summer outlooks, please tune into our Commodities Spotlight podcast — Wholesale power markets prep for summer heat, demand and possible emergencies — where our North American market reporters will dive into specifics.

The post Summer peakloads could put stress on some US power markets as heat pushes up demand appeared first on The Barrel Blog.

Source: http://blogs.platts.com/2018/05/23/us-summer-peakload/

55 – A Calgarian’s Lament about Amazon’s Rejection

Calgary didn’t make it into the top 20 most attractive cities for the second HQ of the digital Goliath. What does this tell us about Calgary’s brand and how it may need to change for a more digital future? Duration: 10m 14s

The post 55 – A Calgarian’s Lament about Amazon’s Rejection appeared first on Digital Oil and Gas.

Source: http://digitaloilgas.com/55-a-calgarians-lament-about-amazons-rejection/

Iron ore quality differentials evolve as market fundamentals shift

Since January S&P Global Platts quality differentials for the gangue elements such as alumina, silica and phosphorous have evolved to reflect changing market fundamentals.

The alumina differential soared 100% from $1.50/dmt in January 2018 to $3.00/dmt in May 2018. Phosphorous has also seen large increases from a steady $1.30/dmt throughout the last quarter of 2017 to $2.50/dmt on May 18, where it has remained.

The most extreme moves have been seen across both silica differentials, but especially the high silica band of 6.5-9%, which collapsed from $7.00/dmt in January to $2.50/dmt today and is still on a downward trend despite a strong steel mill margin recorded to date.

Platts Quality Differentials


Platts China domestic steel mill margins


The recent fall in the silica discounts has been triggered by an adjustment in global supply. The winter seasonal reduction in Chinese domestic supply, which typically contains elevated silica, was one contributor.

The second was the announcement from Vale that it will cut 19 million mt of supply from the high-silica mining area, the Southern System.

This has resulted in lower silica in Vale’s flagship product BRBF. The overall global balance of silica supply in iron ore products has declined, meaning silica differentials have retreated.

Supply concerns over falling domestic production, divergence of iron ore origins at Chinese ports


Aluminum and phosphorous have remained at elevated levels. In general, products from the Pilbara, Western Australia tend to have higher alumina than those from Brazil. A purchasing manager at a steel mill in the Hebei province said: “The higher premium on low-alumina cargoes and the larger discount on high alumina cargoes both suggest that BRBF price performance was stronger, even compared to Pilbara Blend Fines.”

The chart above shows Chinese port stocks of iron ore with a widening divergence by origin, with demand continuing to focus on low-alumina ores, reducing Brazilian stocks as Australian ore stocks rise. Adding to the tightness is declining Chinese domestic supply due to increased production costs for the first quarter of 2018. “Demand for cargoes with different specifications for sintering played a more important role when concluding the trades,” a Singapore-based trader said. “With the thinning out of low-alumina iron ore supply, mills were actively seeking low alumina feedstock, which were composed mainly of domestic Chinese concentrates or Brazilian materials.” Besides, the largest pellet supplier into China is India, sending around 800,000 mt/month of pellets. Indian pellets are generally higher in alumina than pellets from Brazil, historically the largest supplier of pellets into China prior to the Samarco incident.

High alumina levels can hurt productivity in the short term in the blast furnace by increasing the viscosity of the slag. This can slow the process of tapping the slag prior to the hot metal. Over the long term, high alumina can also cause a build-up of solids that precipitate from gas in the upper cooler zone on the blast furnace walls. It is possible that the build-up of solid matter can grow and eventually drop into the burden mix. This can cause a temporary cooling of the burden, reducing productivity and increasing coke demand to bring it back up to the required temperature.


Aside from the adjustment in global supply that has reduced silica differentials, falling metallurgical coal and coke prices could be another contributing factor. In a blast furnace, the formation of a suitable slag is critical to maintain optimal conditions. The level of silica relative to other compounds, notably the ratio with CaO (sourced from the flux), helps determine slag conditioning. The melting of metal and slag is aided by reduction reactions, provided by combustion of reductants, mainly coke. In simple terms, the higher the slag volume per mt of hot metal, the higher the rate of coke consumption and reductant costs. A general rule of thumb in furnace chemistry is that for every +0.1% Si increase in hot metal, the coke rate increases by +6.5kg per mt. So we believe the silica penalty should in part be a reflection of metallurgical coal and coke prices, which directly affect the cost of reductants in the iron-making process.

Lower silica discounts could in part be a reflection of metallurgical coal and coke prices

Both metallurgical coal and coke prices fell more than 20% between January and April, before settling at approximately $198/mt and $317/mt, respectively, in the last week. The chart above shows a positive correlation, especially between low-silica differentials and domestic coke prices. According to Platts calculations, the latest average silica penalty of $0.50/dmt observed in the spot trade would reflect a much lower coke price than we see today. At current coke prices, we would expect the silica penalty differentials to recover, especially as the steel mill margin continues to hold strong.

The post Iron ore quality differentials evolve as market fundamentals shift appeared first on The Barrel Blog.

Source: http://blogs.platts.com/2018/05/23/iron-ore-quality-differentials-evolve/

First import of Western Canadian crude since Aug 2015 arrives: In the LOOP

The Louisiana Offshore Oil Port last week received a cargo of Western Canadian crude, the heavy sour grade Access Western Blend, which appears to be the oil terminal’s first import from that region in recent history.

Marathon imported last week about 579,000 barrels of 24.1 API Access Western Blend on the 109,000 mt Aframax tanker Seavoyager, which originally sailed from Vancouver, according to US Customs and Platts Analytics data.

Cenovus was listed as the shipper. It departed Vancouver on April 19, moved along the Pacific Coast of North America before transiting the Panama Canal around May 5-6 and arriving at LOOP around May 11, according to Platts vessel-tracking software cFlow.

LOOP has not previously imported any Western Canadian crude by water, having only before seen Eastern Canadian grades Hibernia, Terra Nova and Hebron, according to data dating back to August 2015. Most market sources seemed to think this may have been LOOP’s first import of Western Canadian crude by any means; however, there is not the same level of visibility into pipeline shipments of crude as there is for waterborne movements.

“[Western Canadian Select] has made it to LOOP via vessel in the past but nothing on the pipeline,” said one source who is familiar with LOOP operations.

Other sources were in agreement that the only pipeline option would be Shell Midstream’s Houston-to-Houma, Louisiana, Zydeco crude pipeline, but that pipeline handles light sweet grades and not heavy sours.

US Customs and Platts Analytics data shows just four US waterborne imports of AWB. In addition to the LOOP import last week, there were roughly Aframax-sized imports in October at Texas City, Texas, and February and April at Long Beach, California.

LOOP did not respond to a request for comment.

Access Western Blend is typically 21.8 API, 3.9% sulfur with high metals, according to Crude Quality Inc., which maintains the Western Canadian online crude data bank http://www.crudemonitor.ca. It is a blend of bitumen and diluent, according to co-producer MEG Energy. Market sources say it is typically valued anywhere from $2.40/b to $1.90/b less than regional heavy sour benchmark
Western Canadian Select. Like WCS, it arrives in the Houston refining center by pipeline. AWB has been exported out of the US Gulf Coast. In late October, Lukoil shipped 22.2 API, 3.81% sulfur AWB from Port Arthur, Texas, to Shandong, China,-based Haiyou Petrochemical.

Hedging is a complicating factor, with no established US Gulf Coast marker for medium or heavy sour crudes, even though most regional refiners maintain a steady diet of these crudes.

The ‘In the LOOP’ Americas crude oil wrap runs each Monday in Crude Oil Marketwire, North American Crude and Products Scan and on the Platts Global Alert. You can read the FAQ: USGC LOOP Sour crude here and find the full special report LOOP Sour Crude: A benchmark for the future here. Also be sure to download our LOOP app by searching for ‘Platts LOOP’ in your app store.

The post First import of Western Canadian crude since Aug 2015 arrives: In the LOOP appeared first on The Barrel Blog.

Source: http://blogs.platts.com/2018/05/22/first-import-western-canadian-crude-since-aug-2015-arrives-loop/

What will it take to re-start offshore drilling? | Fuel for Thought

As global crude oil has hit the $80/b mark, the industry is now wondering if there is a magic price that would jump-start the offshore sector which is lagging an otherwise steadily recovering oil patch.

Higher crude prices near-term may not be enough to entice operators back to the risky business of greenfield offshore projects—as opposed to the warm fuzzies and quick payoff provided by North American shale.

“Offshore is starting to look a bit better” as onshore breakevens rise due to high activity, S&P Global Analytics analyst Rene Santos said.

“For offshore, due to relatively low activity, service provider costs [for] rigs and fabrication yards continue to decrease, Santos said. “However, shale breakevens are still around $10/b lower than offshore—low $40s/b versus high $40s/b WTI.”

Other encouraging signs are afoot that could make offshore look better. A few more final investment decisions than expected were taken this year on medium-sized projects and more of them involve liquids—both potential harbingers of an offshore uptick, brokerage firm Bernstein said.

Consultants Rystad Energy earlier this month estimated 40 more offshore projects globally will be sanctioned this year than the 60 in 2017.


Yet those who are close to that sector say these signs are not enough for many industry operators to warrant plunging back into an offshore business that remains risky and expensive, when onshore shale plays continue to beckon with quicker returns and less uncertainty.

“With 10 major oil companies accounting for 70% of total deepwater activity, the list of active names is short and none are likely to step up meaningfully as long as they have unconventional acreage in the US,” Credit Suisse analyst James Wicklund said in a recent investor note.

It will take more than higher oil prices to move the needle on more offshore drilling, Bernstein analyst Nicholas Green said in a recent investor note.

Green, who in March performed an extensive analysis of the state of global offshore, sees at least eight metrics that may help gauge if and when the sector is in authentic recovery and not just in fingercrossing mode.

They include:
„„* A conviction that an offshore supply deficit is crystal-clear.
„„* “Substantially” better field economics for the average offshore project.
„„* More oil projects sanctioned.
* „„A greater number of contract awards spread out globally.
„„* Investors’ desire for output growth and reserve replacement.
„„* Corporate price decks adjusted to a higher oil price.

His conclusion is that the current set of conditions “lacks the proof we are looking for.”

“Oil price looks great and optimism is returning [but] oil companies are in no hurry to increase their capex,” Green said. “Crucially, the activity of one basin—Norway—single-handedly underpins the recovery in our datasets and the dollar value of order intake remains poor.”


One clue to the state of the offshore industry may lie in the most recent US Gulf of Mexico lease sale last March. Many called the event lackluster since it captured just $125 million in high bids—less than half the $275 million in March 2017, and far less than the $500 million average of the three years before that.

But the reasons for the low bids is an indication of current oil company thinking, based on the reality of new market conditions, Tommy Beaudreau, former BOEM director and now a partner at law firm Latham & Watkins said.

US Gulf of Mexico crude production

Since early 2015, offshore companies have relentlessly reduced costs and lowered breakeven prices for oil—a “painful” process which has made that arena’s activity more competitive in the long run, Beaudreau said in a paper for Columbia University’s Center on Global Energy Policy.

“The offshore industry has [taken a] more strategic, value-driven approach to leasing decisions” in the Gulf of Mexico, resulting in fewer tracts receiving bids, he said. But “when… a particular tract makes strategic sense and offers value, companies still will spend millions for a single lease block.”

The industry will need to reach a “psychological point,” passing through several stages, before operators naturally gravitate to offshore exploration and development make sense again and offers value, Keith Myers, president of research for Westwood Global Energy Group said.

Myers suggested getting to that point will involve an evolution: oil prices staying above $60/b over time, which in turn provides operators enough funds to cover capital spending and dividends, so shareholders and the board are satisfied and begin calling for the next level of expansion.

“It’s the point where management teams and … investors start saying, ‘Where’s your growth? Where is your high-impact drilling? How do you sustain yourself into the future and grow your top line’?” Myers said.

“Above $60/b is a crucial number,” he added. “When you … are confident that the long-term price of oil will be above $60/b, that will unlock a lot more investment.”

The post What will it take to re-start offshore drilling? | Fuel for Thought appeared first on The Barrel Blog.

Source: http://blogs.platts.com/2018/05/21/offshore-drilling-deepwater-exploration/

Rising USGC sour prices prompt more imports: In the LOOP

US crude imports into the Louisiana Offshore Oil Port appear to be on an upswing in May alongside the recent increase in regional sour crude prices.

About 3.95 million barrels of crude was imported into LOOP in the first decade of May, or roughly 395,000 b/d, according to the most-recent US Customs Bureau and S&P Global Platts Analytics data, compared with an average of 327,000 b/d in the first four months of 2018.

Roughly half of those barrels were Basrah Light and Basrah Heavy imported from Iraq while the balance comprised Argentinian Escalante, Kuwait Export Crude and Mexican Maya barrels.

Marathon imported 2.4 million barrels of that amount while ExxonMobil and Trafigura imported about 975,000 barrels and 545,000 barrels, respectively.

The uptick in crude imports at LOOP coincides with a recent increase in regional sour crude prices.

By midday Monday, the US Gulf of Mexico offshore grade Mars was heard bid-ask at a 65 cents/b-$1/b premium to cash West Texas Intermediate at Cushing, Oklahoma. That put its value somewhere around plus 70 cents/b to cash WTI compared with plus 45 cents/b at the beginning of May and minus 60 cents/b at the beginning of March.

The increases have been due in part to scheduled maintenance on Shell’s US Gulf of Mexico Mars and Ursa platforms, which began in late March and continued into at least mid-April.

Other regional sour grades similarly have risen. The medium sour blend LOOP Sour ended last week 75 cents/b above its value at the beginning of March while Southern Green Canyon is up $1.35/b over the same time period, S&P Global Platts data show.

The hike in prices and increasing refinery runs ahead of the driving season are likely boosting regional imports, particularly of heavy and medium sour grades, favored by regional refiners despite booming production of light sweet crude in the US.

Data from Platts cFlow trade flow software show another four VLCCs likely headed to LOOP from Saudi Arabia, Iraq and Singapore. The tankers include the Aquitaine, FPMC C Melody, New Laurel and Sahba, which are expected to arrive between Monday and June 16, the data show.

The ‘In the LOOP’ Americas crude oil wrap runs each Monday in Crude Oil Marketwire, North American Crude and Products Scan and on the Platts Global Alert. You can read the FAQ: USGC LOOP Sour crude here and find the full special report LOOP Sour Crude: A benchmark for the future here. Also be sure to download our LOOP app by searching for ‘Platts LOOP’ in your app store.

The post Rising USGC sour prices prompt more imports: In the LOOP appeared first on The Barrel Blog.

Source: http://blogs.platts.com/2018/05/15/loop-rising-crude-imports/

#Ulterra will speak at 11 AM on 5/22 on “More Than Just ‘New’: Putting Drilling Problems First” https://twitter.com/HartEnergyConf/status/994638392821534721 …

will speak at 11 AM on 5/22 on “More Than Just ‘New’: Putting Drilling Problems First” https://twitter.com/HartEnergyConf/status/994638392821534721 …

source https://twitter.com/UlterraBits/status/996068581313056771
Source: https://ulterra.blogspot.com/2018/05/ulterra-will-speak-at-11-am-on-522-on.html