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Venezuela’s power struggle a race against time: Fuel for Thought

Venezuela’s oil industry is at risk of grinding to a halt, along with the rest of the nation, as El Guri, Venezuela’s largest hydroelectric power facility, could see a drop in output of 3,800 megawatts if eight of 18 turbines are shut down.

That would be roughly a quarter of the power produced in the country.

Since the national electric grid powers the oil industry from oil wells, to refineries, natural gas processing plants and marine terminals, loss of power from Guri would be crippling.

This situation is highly possible if reservoir levels keep falling. The government appears to have no immediate solutions and instead talks of lofty goals on converting its diesel-run power plants to be fueled by natural gas.

The Guri dam was at 242.88 meters at the end of April and shutdowns would begin if it reaches 240 meters.

While it has started to rain recently and forecasts for a few centimeters of rainfall over the month provide a bit of a cushion, it may not be enough.

“Average drawdowns on reservoir levels for May are normally around 6.4 cm — considering current savings due to power rationing are at around 20%, it is going to be really touch and go whether they make it through May,” FGE analyst Thomas Olney said.

Rather than developing shorter term solutions like expanding existing infrastructure and capacity in its diesel-run power plants and taking advantage of falling global gasoil demand, the government announced plans to convert its diesel-driven power plants to run on natural gas.

Energy Minister Eulogio Del Pino estimated they would be able to export 500,000 b/d more diesel rather than use that to run power plants.

Venezuela needs to export more oil products in order to increase its foreign currency earnings as not only is the country short water, it has a severe fiscal crisis that may get worse if it can’t meet multi-billion dollar bond payments coming up over October and November.

But the feasibility of such a plan is a big question mark.

“When Del Pino [talks of] that replacing 500,000 b/d of oil products, he does not say that it would require additional gas production of 2,900 Mcf/d… which PDVSA is far from doing,” said Venezuelan consultant Einstein Millan.

Natural gas to the rescue?

Venezuela certainly has the natural gas resources to run its power grid with the second largest reserves in the Americas behind the US of 196 Tcf, according to the US’ Energy Information Administration.

The question is how to unlock those reserves. Venezuela is already forecast to run a gas deficit this year of 1,947 Mcf/d, according to independent analyst Nelson Hernandez.

Eni and Repsol started offshore gas production in the giant Perla field last July, and production of five out of seven wells is pumping out about 510 Mcf/d of gas with targeted peak production in 2020 of 1,200 Mcf/d.

Even at peak production, it would not cover the current gas deficit, let alone additional expected were to convert to gas.

Rosneft also recently signed a deal to jointly develop offshore gas in the Mariscal Sucre field and maybe past won’t be prologue, but the field they are planning to develop has about a 20-year history of failed development efforts behind it.

In order to develop natural gas production, installing necessary infrastructure as well as paying for converting power plants to run on natural gas requires funds that Venezuela does not have.

Another possibility is all of the foreign firms operating in mixed JVs in the country could be forced to cough up more money as the government has demanded or risk losing their production rights. So far there’s been no additional money announced from those companies to the government. If they were to lose production rights, it brings up the question as to who would be left to manage and invest in the ventures and production could suffer even more.

Since the Guri dam supplies about 70% of the nation’s power demand, if it fails, social unrest could escalate and the government itself would be at heightened risk of collapse.

This could be another reason deals with the government may not happen as it would become riskier to make a deal with a regime that may not be in power in a year’s time.

Source: http://blogs.platts.com/

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US steelmakers rummaging in the trade case toolbox for imports relief

It took four years, but we might now know what former Nucor CEO Dan DiMicco meant in 2012 when he said Nucor was “exploring some very new and unique ways” of combating unfairly traded steel imports.

“There are opportunities for us to deal with this today with tools that are in the toolbox and tools that will be added to the toolbox,” DiMicco said during an earnings call in October 2012.

Since then, US steelmakers have petitioned for antidumping and countervailing duty (AD and CVD) investigations on oil country tubular goods, rebar, wire rod, welded line pipe, corrosion-resistant sheet, structural tubing, cold-rolled coil, hot-rolled coil, cut-to-length plate and other steel products.

After the wave of AD and CVD duty investigations in the last few years, we’re now hearing US metals companies touting new tools — such as last year’s provision lowering the injury standard — and calling out so many sections of US trade law that it’s starting to sound like trade case bingo.

201. 232. 337. 332. They conjure a sort of trade case numerology that requires a deep understanding of the myriad ways domestic industries can confront unfair trade, although there has been no recent mention of 301, which has been unsuccessful for steel at least thrice, or the mystical Super 301.

“It’s time now that we do something substantial. It’s time now to send the message that we’re not going to have to keep coming back case after case and year after year for 15 more years,” Leo Gerard, president of the United Steelworkers union, said at an International Trade Commission hearing. “It is time that the administration leads a 201. It is time that the administration put forward an investigation on a 232.”

Steel Dynamics Inc. CEO Mark Millett testified that launching a Section 201 proceeding was “likely the only viable solution to restore financial health to steel manufacturers and pipe and tube producers.”

So, what do all these numbers mean?

Section 201, Trade Act of 1974 – A Section 201 action is probably the most commonly known trade action for steelmakers besides AD and CVD cases and it has helped the industry before. Unlike AD and CVD cases that have to be filed on products and name countries individually, Section 201 actions — also called safeguards — impact all imports of specific products no matter the origin. They’re also are enacted more quickly.

In 2001, the ITC recommended a four-year Section 201 program with tariffs for multiple steel products and tariff-rate quotas for import volumes exceeding certain amounts. These actions require presidential approval, and President George W. Bush signed the duties into effect in early 2002. However, under international pressure, Bush removed them in late 2003. Section 201 actions require a more rigorous process because the domestic industry must prove “serious injury,” not just “material injury” to the ITC.

Section 232, Trade Expansion Act of 1962 – Section 232 investigations are used to determine the impact of imports on national security. The Department of Commerce conducts the investigation and then makes recommendations to the president within 270 days of receiving an application. The president has 90 days to decide if he (or she) agrees and will “adjust imports.” This is the tool that steelmakers pulled out recently and said, “Oh, I forgot I had this. I don’t remember if it is any good.” In 2001, Commerce investigated the effect of imports of iron ore and semifinished steel on national security, but in the end, recommended no presidential action.

Section 337, Tariff Act of 1930 – Section 337 makes infringement on intellectual property rights and other forms of unfair import competition unlawful, according to the ITC. This is a tool that’s being used in a different way. While it is typically used to allege patent infringement, US Steel in April requested Section 337 investigation of all Chinese carbon and alloy steel products, alleging that Chinese steelmakers conspired to fix prices, stole trade secrets and circumvented duties by false labeling. The ITC acts as a sort of patent court in these cases, and if it decides to move forward, it will assign an administrative law judge to the case. In about a year and a half, the judge makes a determination, which is subject to presidential review. The reward for a successful 337 case is an exclusion order, which will instruct US Customs and Border Protection to not permit imports of the subject product.

Section 332, Tariff Act of 1930 – A Section 332 investigation is a fact-finding mission for trade or tariff matters. In these cases, the ITC investigates international trade, tariffs and competition between the US and foreign industries, but in the end, it makes no recommendations. The House Committee on Ways & Means in February requested a study called: “Aluminum: Competitive Conditions Affecting the US Industry,” which people in the market have said will give more detail about the portion of the US market being served by alleged illegally dumped Chinese aluminum.

Section 301, Trade Act of 1974 – Section 301 is intended to enforce trade agreements, resolve trade disputes, and open foreign markets to US goods and services. US steelmakers petitioned the George W. Bush administration in 2007 to investigate allegations that currency manipulation by China was a de facto trade law violation, but Bush refused. Section 301 remedies include the imposition of duties. Bush also rejected steelmaker 301 petitions in 2004 and 2005.

OK, got it? There won’t be a test on this, but it may be wise to be prepared anyway. Sometimes the trade tool box seems more like Pandora’s Box, especially when you consider that other countries have their own tools, too.

Source: http://blogs.platts.com/

Inside Nippon Steel’s Kashima plant: Do you want to know a secret?

“No photos!” a pouncing PR person tut-tutted. Yoko was more amused than bemused as she holstered her smartphone once more.

Colleague Yoko Manabe and I were part of a Japanese media group touring the integrated steelworks of Nippon Steel & Sumitomo Metal Corp at Kashima, northeast of Tokyo. We’d been mustered inside the cavernous building housing the No.1 blast furnace where the furnace house superintendent was listing the attributes of the 5,370 cubic meter giant with fatherly pride.

A diligent scribe, Yoko had taken out her phone to record the fascinating minutiae because the safety goggles, gloves, helmet, water bottle, headphone set and C02 detector we’d all been provided with were hampering efficient note-taking. Alas, photo-capable iPhones were a no-no.

As the tour wore on, the no-pictures rule became more perplexing. To be fair, NSSMC had allowed us to capture the outside of the furnace from a bus stop for a few minutes of furious clicking. But the photo restriction seemed increasingly absurd.

I’ve toured countless Japanese steel works, smelters, coil centers, fabrication shops, and end user plants, many of which have really cool set-ups and are doing amazing cutting-edge stuff. So a reluctance to let tourists wander around taking happy snaps of intellectual property is understandable and justifiable.

And then there’s Kashima. The Kashima plant was inaugurated nearly five decades ago by the former Sumitomo Metal Industries (which Nippon Steel absorbed in October 2012 to form NSSMC). The works is spread over 8.9 million square meters and, like all contemporary Japanese mills almost entirely dependent on imported steelmaking raw materials, is built close to the sea. Today, age, sea-air corrosion, and iron ore dust have given Kashima the visage of contented decay.

As much as The Beatles and the Mini Cooper S, Kashima is a product of the ’60s and still employs the technology of those times. Whereas far younger rivals in China, South Korea, Vietnam and elsewhere employ direct charging and casting of steel, Kashima continues to trundle molten iron and steel in a fleet of torpedo cars, the massive football-shaped vessels that contain 300-400 mt. A staffer proudly told me that a fully laden torpedo car can cover the 1.1 kms journey between the No.1 steel shop and the No.3 casting shop in 12 minutes, ignoring the inefficiency of all that loading, unloading and shunting.

Emblematic of the time-slip was Kashima’s heavy sections mill producing H-shaped construction steel. Built in 1975, a roll on a roughing mill bore the names ‘Hitachi Zosen’ and ‘Demag,’ companies that no longer exist. Demag, part of German plant builder Mannesmann Demag, was spun off into SMS Schloemann-Siemag AG in January 1999. Two years later Hitachi Zosen, NKK Corp and Sumitomo heavy Industries spun off their heavy machinery divisions into Steel Plantech.

Hence my consternation. What exactly did NSSMC fear a smartphone photographer at Kashima would capture that might advantage competitors?

Most likely, the no-photos rule is age-old and one for which seeking exceptions is too cumbersome.

But it could also be this: The Kashima works produced first its first steel in 1971. In the year to March last year, it produced 7.6 million mt of steel, accounting for 17% of NSSMC’s total output. After the Oita works on Kyushu and the Kimitsu plant in Chiba, Kashima is NSSMC’s third-largest and accounts for 7% of total Japanese raw steel output. Last year 54% of its production was exported. As of March last year it employed just 3,130 staff, making Kashima one of the most efficient plants operating in Asia today.

That a rust-pocked 45-year old steelworks is still employing long superannuated machinery – and machinery long-since fully depreciated – with minimal staff and yet can still produce some of the world’s best steel and in large quantities is probably a secret NSSMC wants keeping.

Source: http://blogs.platts.com/

Recovery of US coal industry is more than a fairytale

Unless you’ve been hiding under a rock — perhaps buried by mountainous utility stockpiles — you’ve probably heard the US thermal coal market is struggling. Demand is down. Production has plummeted. Prices are low.

Some of the largest coal producers in the nation have filed for bankruptcy, and most others are doing whatever they can to try and stay in business — a tough task in a market facing more challenges than ever.

But despite the black cloud enveloping the industry, deep down is a seam of optimism filled with hope, recovery and a brighter future. A better coal market is coming, people in the business say, simply because it can’t get any worse than this.

That belief in a better tomorrow is why almost 500 coal professionals flocked to Orlando, Florida, last week to attend the Eastern Fuel Buyers Conference, one of, if not the, premier industry gatherings of the year.

At the 45^th annual event, organizers looked to shine a coal-fueled beacon of hope with a conference theme of “20/20 Vision – Coal’s Path to the Future,” and there was probably no better place to tell that magical tale than at Walt Disney World.

Reality sets in

While the conference focused on how the US coal industry would eventually transform into a healthier one, notions of King Coal’s return to the throne were nonexistent near Cinderella’s Castle. The reality of today has slowly sunken in, and the carriage has turned into a pumpkin.

Prices for natural gas, coal’s evil stepmother, are still low, and the sinister stepsisters of elevated utility stockpiles and environmental regulations continue to torment the market.

Coal’s Prince Charming, alas, was nowhere in sight — unless that turns out to be Donald Trump.

“We’re all hurting, all parts of the industry,” one producer said at the conference. “You come here looking for hope and looking to talk to the people who are going through the same thing you are going through. You share war stories. You share ideas. You try to figure out what you can do to stay afloat.

“We’re all like a family,” he added. “You see these people every year, and we’re all going through it. You want everybody to do well, but the fact is that isn’t going to happen. You have to see what you can learn here to be the best company you can be until we hopefully see an improvement.”

When a better market develops is a huge unknown. Some in the industry see 2016 as a bottom for US coal, while others at the conference expect 2017 to mirror this year’s struggles.

Consolidation is key

Despite contrasting views as to when we’ll see coal begin to recover, a consensus among presenters and attendees alike was consolidation is needed before there is any significant improvement in the market. Less coal demand will mean less production and fewer companies supplying power plants.

US thermal coal consumption for the electric power sector topped 930 million st five years ago, dropped to 740 million st last year and could fall to as little as 650-700 million st this year, some have predicted. Consumption figures at the end of 2016 could equal what the new annual demand will be for years to come.

Some consolidation will come through bankruptcies, as companies liquidate assets and other producers scoop up coal mines through the courts. More consolidation could happen as producers look to shrink their footprint or get out of the industry altogether, sources said.

Jim McCaffrey, senior vice president of energy marketing at CNX Coal Resources, spoke at the conference and said more reorganization of the industry not only will come but is needed.

“I think the focus needs to be on regional consolidation rather than national diversification,” McCaffrey said. “Obviously, we have companies that are bankrupt, we have companies that aren’t. I like to say every company in the coal industry has reorganized. Some have done it with the help of the courts, some have done it without the help of the courts, and I think that reorganization will continue.”

Plenty of questions remain as to what will happen this year and further out as the entire energy sector continues its transformation: What will be left after all the big coal bankruptcies? How much coal will utilities burn? When will natural gas prices go up? Will there be a Clean Power Plan?

With all that uncertainty, everybody can agree on only one thing for sure: The US coal industry won’t ever be the same.

Source: http://blogs.platts.com/

America’s one million b/d of crude oil for president

Brian Scheid spoke this week at the Platts Global Crude Oil Summit in London and gave some insight into one of the biggest variables around US oil: the next president.

Let’s call it the 1 million b/d race, even if such speculation may ultimately prove wildly wrong.

In short: no one can accurately forecast the impact of the outcome of this November’s US presidential race. This is partly because neither Hillary Clinton, the Democrat’s likely candidate for the White House, nor Donald Trump, the presumptive Republican nominee, have laid out the specifics of their energy policy hopes. Nor is it clear how many of these policies may bear fruit.

More importantly, the race for the White House and its subsequent effect on global crude oil market fundamentals will not happen in a vacuum. A coordinated supply cut by OPEC, a collapse of Venezuela’s economy, even a pronounced return of Libyan oil to the world market will likely impact fundamentals deeper than whatever happens in November’s election. In addition, if oil prices sink below $30/b again or return to levels above $70/b, the new White House tenant’s influence on crude supply and demand may ultimately be inconsequential.

There are so many variables that the US Energy Information Administration, which forecasts everything from where Brent spot prices will be trading next year to how much a single Eagle Ford rig may produce next month, does not forecast the impact of election outcomes on oil, or any other energy markets.

Several analysts cautioned that trying to predict the market impact of the likely race between Clinton and Trump was a fool’s errand at best and pretty much impossible. But they did offer a best case/worst case view that a Clinton win would broadly decline production, by as much as 500,000 b/d, and a Trump win could boost production by as much as 500,000 b/d. So, the election could have a 1 million b/d swing, even if such a prediction is informed speculation, or, as some might more accurately put it: a guess.

That being said, this presidential race is shaping up to have a major impact on the direction of US and, possibly, global oil supply and may have the most significant impact on oil policy of an election in American history. This is partly due to the increasing move away from middle ground in American politics which has clearly been accelerated amid the presidential primary races. This has caused candidates who may have a more nuanced view on energy policy, such as conditions on fracking on public lands, to a more extreme view, such as an all-out fracking ban.

Factor in the likelihood that the partisan balance of Congress and the Supreme Court will also be decided by voters in November, the possible shift in US oil policy may be unprecedented.
With all these moving parts and potential variables, here are some of the key possibilities for crude markets if Clinton or Trump win in November.

If Trump wins

While Trump has offered few specifics on his energy policy goals, he has indicated that several extreme possibilities, such as a ban on Saudi Arabian crude imports, are being considered.

Possibly the bigger crude policy game changer is the possibility that Trump could void the historic nuclear deal with Iran, a result which could put a massive sanctions regime back in place and might limit access by US allies to the US financial system.

President Obama has made efforts to combat climate change a legacy goal. This includes new rules to cut methane emissions from oil and gas wells, making it harder to drill on federal lands and, arguably, more expensive to drill anywhere else. He’s also limited the offshore areas where production can take place and has come up with strict new technical standards for drilling both on and offshore.

As president, Trump would likely try to gut all that. The costs, the burdens of federal regulations on oil and gas drilling could go away. In essence, it would be easier and less expensive for a US producer to produce.

Trump could also look to weaken fuel economy standards set by the Obama administration, creating a major demand boost, and might look to open more federal waters to oil and gas production.

The Obama administration seems to want to concentrate offshore production to only one area: the Gulf of Mexico. They recently took a planned oil and gas auction for parcels in the Atlantic Ocean out of their upcoming five year lease sale plan. And after Shell’s missteps in the Arctic, they seem to be taking great pains to keep any drilling from taking place offshore Alaska. In October, the administration cancelled two planned sales of Arctic oil and gas leases: a sale planned for this year in the Chukchi Sea and one planned for next year for parcels in the Beaufort Sea.

Trump could put everything on the table: Atlantic lease sales, Arctic lease sales, more Gulf drilling, maybe even the Pacific. There are some timing issues with that, since they couldn’t undo Obama’s leasing plan through 2022 without considerable delay and effort. But all available US waters could conceivably be opened up to oil and gas drilling within a decade.

Just because those waters are available, however, doesn’t mean producers would necessarily want to develop them. Like the impact of the election, there are a lot of variables at play.

In addition, if Trump moved to open more public land to drilling, as many expect he would do, it’s unclear if such a move would be met with much enthusiasm from producers.

If Clinton wins

If elected, Clinton has pledged to, within a decade, “reduce American oil consumption by a third through cleaner fuels and more efficient cars, boilers, ships and trucks,” according to her campaign website.

While the potential path isn’t entirely clear, the oil and gas industry is nervous that Clinton could move toward banning fracking on public lands, cutting off the possibility of future production. Clinton has outlined conditions for fracking on public lands, including needed approvals from states and municipalities and chemical disclosures, but industry lobbyists stress these conditions could become a de facto ban.

The main view on a Clinton, or Senator Bernie Sanders, presidency, is that it would essentially continue and push President Obama’s efforts to combat climate change further. So a plan to limit methane emissions from new oil wells gets expanded to emissions limits on all wells.

Maybe a $10-per-barrel tax on oil that Obama pitched earlier this year, but went nowhere, gets resurrected in a Clinton White House. In addition, elimination of tax incentives oil companies get for drilling in the US would likely get a hard look.

Perhaps a Clinton White House would get more ambitious with federal gas mileage standards, going beyond 54.5 miles per gallon goal in 2025, further decreasing gasoline demand.

A big difference will likely be offshore drilling. Instead of keeping the Atlantic Ocean free of oil and gas drilling for the next five years as the Obama administration has proposed, it would likely be kept out of there for 10 or 15 years by a Clinton administration.

More parcels offshore Alaska would likely be taken off the table; maybe US producers never return to offshore Alaska until a Republican wins the presidency. Maybe future lease sales in the Gulf of Mexico are cancelled. This is major from a supply standpoint.

Despite the impact that prices have had on the US shale revolution, Gulf of Mexico production is expected to hit record highs in 2017, averaging 1.63 million b/d in 2016 and 1.79 million b/d in 2017.

If you’re enacting policy that potentially cuts US Gulf production then you’re talking about cutting into one of the few sources of US supply that increases even in a bust cycle.

Even without specifics, this election matters deeply to fundamentals and will be a key moment for US producers and the path of supply. Who wins in November may dictate if the US shale renaissance peaked 9.75 million b/d in April 2015 or if this year has been a dip ahead of a new high.

Of course, if oil returns to $100/b, even $70/b, it may not matter much to producers who is in the White House.

Source: http://blogs.platts.com/

China’s commodity exchanges capable of cooling any futures trade frenzy

Roller-coaster game is the best metaphor to describe what has happened to China’s steel, coking coal, coke, and iron ore futures in the past two weeks where prices are concerned. And of course, not surprisingly, the exchanges — as the watchdogs — have contributed to the price fluctuation since over April 21-May 10.

The Shanghai Futures Exchange (SHFE) and Dalian Commodity Exchange (DCE) both intervened a few times too during the past two weeks just to cool the trading frenzy in their respective rebar, hot-rolled coil and iron ore, coking coal and coke futures contracts, via the means of raising the daily price fluctuation caps, transaction fees, margins, and blacklisting those individuals that have been too frequently opening and closing positions on the daily basis, blocking them from trading for one month.

Besides, SHFE also shortened the night trading hours of rebar and HRC to 2100-2300 Beijing time starting May 3 from the original 2100-0100. This was welcomed by a Shanghai trader, saying, “Finally I can get some sleep instead of staying up late into the midnight.”

The bourses have taken these steps after future prices of all the above commodities hit daily caps on April 21 amid high trading volumes. This concerned China’s central government, as it will inflate physical values and thus make it more difficult for Beijing to tackle overcapacity in the steel sector.

“[The] Chinese economy is full of complexity nowadays, and it is a hard task to stabilize the economy while going through restructuring, under such circumstances, [the] futures market is supposed to help and serve the economy,” DCE said in a statement Monday.

However, the frenzy of speculative trading in iron ore, coking coal, and coke futures — mainly by individuals — will only multiply the risks and expose investors to greater vulnerability, it added, confirming the Chinese market sources’ understanding.

A Beijing-based iron ore trader felt the impact keenly. “No one had expected physical iron ore price to have swung by $10/dry mt in a few days to hit $70/dmt in late April, as fundamentals, changing little, are unlikely to have caused such dramatic moves. So, it has been because of the iron ore futures on DCE, as too many people are speculating on it,” she said.

These emergency measures “have sent a strong message to investors, especially to individual investors, that recent price surges in steel-related futures are not welcome at all,” a Beijing-based steel analyst noted.

He acknowledged many more individuals in China have jumped into iron ore and steel futures trading.

The two exchanges’ cooling efforts have been effective so far — SHFE’s HRC trading volume, for example, dropped 15.1% day on day to 239,533 lots as of April 26, while that of DCE’s most popular September iron ore futures contract slumped 49% from April 21 to 3.3 million lots as of April 26, the exchanges’ data showed.

Declines have been continuing in the past two weeks, and as of May 10, the Platts IODEX for 62% fines was assessed at $56.1/metric ton CFR North China, down 20.5% from April 21’s high, and the billet price in Tangshan, north China’s Hebei province, the barometer of China’s steel market, fell to Yuan 1,920/mt ($294.5/mt) as of May 10, down 27.3% or Yuan 720/mt from the recent high on April 21.

The battle between speculative trading against the regulators’ intervention has illustrated explicitly that China’s futures market is yet to be 100% free-willed, and it will be under the close watch and surveillance to serve the “greater good” that is so full of Chinese characteristics.

Source: http://blogs.platts.com/

Platts Crude Oil Summit: Debunking the myths

In Monty Python’s Holy Grail King Arthur tells the black knight that he has no arms left, to which the knight replies: “It’s just a flesh wound.” This was how Standard Chartered’s Paul Horsnell described the so-called resilience of US shale production as he went on to critique commonly held views in the market.

The robustness of US production is certainly an important question, not least for OPEC strategy, with Horsnell arguing a sharp rise in the rig count, which is at its lowest ever according to Baker-Hughes, is needed to stabilize output.

Low prices have led to calls in the way the industry works. “No other industry would work backwards from the price of its output (in this case, hydrocarbons) in an attempt to justify the costs of its inputs (i.e. capital and operating costs),” said Allianz’s Chris Wheaton. He joked that the industry has often responded to underperformance with ‘it’s not our fault, the oil price did it,’ and he suggested the use of more technology appears to have increased costs and not cut them.

Wheaton’s key message was that 21st century oil needs to be a manufacturing business: standardization, repetition and low unit costs become competitive advantages. “Shell has 24 shades of yellow underwater paint,” he added, highlighting the overly complex nature the industry needs to address.

Moreover, Wheaton made the point that US shale is an example of poor capital allocation — everyone has capital with little differentiation and no requirement to a make a return on capital (or even return the capital). Shale will not ramp up as fast as it did in 2012-14 due to capital limitations and that the industry needs to deleverage.

The swing producer debate — the ability of a supplier to raise output from spare capacity — was also a hot topic: Kuwait Petroleum Company’s Abdulaziz al-Attar said OPEC will still respond to demand, while US tight oil will respond to price. He added that OPEC will continue to defend market share until the market stabilizes, estimating OPEC’s share will rise to 41.1% in 2017, its highest level since 2012. Saudi Arabia will be reluctant to lose Asian market share to Iran and Iraq and that could put its ability as swing producer in doubt. Energy Aspects’ Amrita Sen suggested that non-OPEC supply outside the US could become a swing factor later this year.

Horsnell also argued that the glut of oil has pretty much disappeared and that the rise in prices is not as speculative as many suggest, detailing the neutral positioning now in the market.

Were there any more myths or Monty Python anecdotes? Maybe the famous dead parrot sketch in reference to OPEC will be at the next Platts summit. “This parrot isn’t dead, it’s just resting.”

Source: http://blogs.platts.com/

US refiners feel the pinch of Renewable Fuel Standard costs: Fuel for thought

Smaller US refiners unable to blend their own gasoline are facing higher RIN costs which are eating into refinery operating costs, as the renewable fuels volumes breech the E10 blendwall.

The US Environmental Protection Agency (EPA) in November mandated the amount of renewable fuels to be used in 2016 to 18.11 billion gallons, which is 10.10% of the year’s expected transportation fuels production.

“Since the new volumetric announcement on November 30 last year RINs prices have almost doubled,” said CVR CEO Jack Lipinski on the first quarter earnings call April 28.

As the majority of gasoline sold in the US is 10% ethanol, it leaves smaller refiners or those without blending capability on the hook to buy RINs, or Renewable Identification Numbers, which are credits which will allow them to make up the difference.

CVR has two refineries, a 115,000 b/d refinery in Coffeyville, Kansas, and a 70,000 b/d plant in Wynnewood, Oklahoma. During the first quarter, the two plants produced 105,878 b/d of gasoline.

Ethanol RINs for 2016, which traded at 54.5 cents/gal on November 30, jumped to 85 cents/gal on December 1, Platts assessments showed. Last week, they were trading in the range of 74.75 cents/gal.

CVR’s first quarter ethanol RIN cost was $43.1 million as compared to $36.6 million in the first quarter of 2015.

So far second quarter ethanol RINs have averaged 73.38 cents/gal, compared with the 61.52 cents/ gal average last year when refiners were mandated to use only 16.93 billion gallons of renewable fuels.

“The RINs market is very opaque, it creates winners and losers and it’s doubtful that it incentivizes additional blending as the EPA has said on many of occasions,” he added.

Refiners are given on a yearly basis individual volumes of renewable fuels they have to blend into the gasoline and diesel they produce, as mandated by the Energy Policy Act of 2005.

RINS A CONCERN FOR 2016

Inland refiner HollyFrontier had $46 million of RINs expense in the first quarter of 2016, and is likely to go into the $50 million/quarter range as their carryover from last year dries up.

HollyFrontier reported first quarter income of $21.3 million, considerably below the $226.9 million earned in the first quarter of 2015, with lower refining margins and costs associated with blending ethanol and purchasing RINs to comply with the RFS mandate as major reasons for the drop.

“RINs are a concern,” said HollyFrontier CEO George Damiris on the first quarter call May 4.

HollyFrontier has five refineries located in the Midcontinent and Rockies regions. These include a 115,000 b/d El Dorado, Kansas, refinery; a 155,300 b/d Tulsa, Oklahoma, refinery; a 102,000 b/d Artesia, New Mexico, refinery; a 47,000 b/d Cheyenne, Wyoming refinery; and a 25,500 b/d Wood River, Utah, refinery.

“During the quarter, costs associated with blending ethanol and purchasing RINs to comply with the RFS mandate had a significant impact as a proportion of earnings,” Damiris said.

“The EPA’s intending to hit if not exceed the blend wall. But also their desire is to dry up the pool of RINs that are available for refiners to carry over from year to year,” he added.

This will force refiners like HollyFrontier to pay more for RINs going forward the the pool of available RINs will shrink or blend more ethanol. Refiners are able to carry over a percentage of RINs from a previous year to apply to the current year’s liability.

“Ethanol this quarter was a big deal, as you can imagine with the lower crude price in the quarter” he said.

During the first quarter, ethanol in the mid-continent was priced at 30 cent/gal premium gasoline, which resulted in a $36 million negative impact on HollyFrontier’s first quarter earnings.

Rising demand from increased driving is narrowing the spread between ethanol and gasoline.

In Chicago, pipe ethanol was priced at $1.53/gal on Wednesday, while unleaded 87 was $1.52/gal, Platts assessment data showed.

Ethanol blending was lower last week, Energy Information Administration data showed.

EIA data shows that conventional gasoline blended with fuel ethanol fell across the nation by 47,000 b/d to 5.753 million b/d for the week ended May 6, while reformulated gasoline blended with ethanol fell 120,000 b/d to 3.187 million b/d.

Source: http://blogs.platts.com/

The bears are back in town: Takeaways from London Metal Exchange week

A “subdued” tone, “the most uninspired week I can remember,” and a poll suggesting only 3% of people believe that Chinese growth rates are what we are told — there was no doubt that the toreros of metal markets had left their bulls at home when they came to London for the annual meeting of traders, brokers, consumers and end-users of metal at this year’s London Metal Exchange week.

At first glance, the fanfare around LME week was said to be similar to years gone by. Conferences in lavish hotels by day and company sponsored receptions by night, but layered with a more solemn mood among the guests. “The food is not as good as it used to be” and “every year there are fewer events” were oft repeated lines among those attending. Considering the state of metals markets, it is no surprise that policies of cost cutting would deter investment in corporate functions.

On top of weak market fundamentals across the metals complex, the number of LME ring-dealing members fell to nine after JP Morgan’s September announcement that it would leave. Compounded with the recent rise of the Shanghai Futures Exchange, having released a nickel contract in March this year which now trades 90% of LME volumes, sentiment was uneasy and questions remained unanswered on what the shape of futures markets would be looking forward.

China doesn’t pander to oversupply

Comparing fundamentals to 12 months ago, it’s not hard to understand the depressed sentiment. In broad strokes, China had not consumed metal at a fast enough rate to keep up with global mine capacity. Comparing the first seven months of 2015 to the same period in 2014 provides some context. According to the World Bureau of Metal Statistics, global mine production of copper grew by 3.42%, yet global refined copper consumption grew by a meager 0.26%, with Chinese growth coming in at 0.69%. Furthermore, China produced and imported less copper over the same period, inferring a draw-down in previously imported warehouse stocks.

This story is well documented and conference halls of London last week converged into an echo chamber resonating with the words “China’s new normal,” indicating that the market must adapt to a slowdown in growth or be swamped in supply. Consciously or not, the market has adapted with vast production cuts. According to Citi Research, 1.6 million mt of copper have been removed from supply this year, with Glencore leading the pack following the suspension of two African copper mines, Katanga in the DRC and Mopani in Zambia, back in early September. More recently, Glencore further lowered their output following the sale of Australian and Chilean copper mines.

Between the first production cuts and LME week, the International Copper Study Group made considerable revisions to their outlook. The new forecast predicted that the market would move into supply deficit in 2016, citing production cuts as the driver of change. Other institutions followed and further cuts were made across the LME metal complex, with Glencore announcing a 33% reduction in zinc production and aluminum major Chinalco shutting 12.5% of its smelting capacity.

Physical prices turn their back to the futures

Production cuts leading up to LME week changed the 2016 outlook of many analysts, with expectations filtering into futures prices. The chart below tracks the prices of a basket of six LME metals through September and October, indexed on Sept. 7, 2015, the day Glencore announced the first production cutbacks.

While the index traded higher during LME week, several traders argued that the cause of higher price levels was a result of an isolated event on Oct. 9: the Glencore announcement that it would reduce zinc production by approximately a third. This caused zinc prices to rally 9.78% in one day, with prices moving to $1,851/mt. Subsequently, the first conferences of LME week on Monday, October 12, were packed with upward adjustments to zinc prices in 2016. Macquarie Research’s punt was that zinc would reach $3,000/mt by October 2016 with the audience widely agreeing, voting it the most preferred long metal on a 12-month view.

As the week went on, the euphoric sentiment surrounding zinc started to dissipate. Attendees at company receptions noted that zinc concentrate had been in surplus for several years now. Every year, LME week provided some upside sentiment, they said, and every year the wait for a tighter market continued. However, several traders noted that treatment and refining charges (TC/RCs) had dropped in the last few months, indicative of lower demand to refine zinc concentrate and a tighter market. For zinc, many hope that this year will be the payoff of several years of pain.

Aluminum: The biggest bear in the room

Aluminum was regarded as biggest victim of oversupply, with fewer production cuts and soaring Chinese semi exports throughout 2015, which amounted to 350,000 mt in September according to Investec, up 2.8% from August. However, there was skepticism surrounding whether the policy of increasing exports is sustainable looking forward.

“There is no real demand for these exports,” one trader commented. “The only reason that exports are still up is to keep up appearances. A lot of this exported material is just sitting in a warehouse in Mexico.”

Copper physicals turn their back on the futures

Event speakers tagged onto this LME “mini-rally” as a reason that production cuts would lead to more balance in the copper market. However, outside the conference hall there was less optimism on whether this would translate to physical momentum. Notably, the release of Codelco’s 2016 European term contract for copper cathode of $92/mt, 18% lower than 2015.

On top of this, there was talk that Codelco would reduce its premiums for material to China to as low $100/mt, representing a 24.81% drop from 2015. Even if the official premium is higher than this, it is indicative of a mood that the fundamental issues facing the market today will not soon go away.

The Chinese takeaway: transparency and oversupply

There was no uniform answer to why fundamentals looked so bleak next year. Some pointed to announcements from other major producers, Rio Tinto and BHP Billiton, to cut the production required to further balance the market. Others mentioned skepticism towards whether China was able to execute a more consolidated infrastructure spending plan, particularly relating to power grid expenditure.

The most novel answer was one of transparency. Following on from the Qingdao port scandal in mid-2014, many metal financing agreements in bonded warehouses became untenable. This led to more metal stock being pushed into LME warehouses on warrant, explaining the ballooning of copper stocks earlier this year. The narrative goes that the unwinding of financing deals provided more transparency this year for the level of global copper stocks, making it harder to hide oversupply and contributing to a bulging surplus unless lower production or higher infrastructure spending is undertaken.

Whatever the reasoning, the unifying trend was that few thought these fundamental issues had quick fix solutions. For the moment, adapting to a “new normal” way to do business looks imperative to succeed in the metals industry.

ource: http://blogs.platts.com/

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Oil and gas M&A heats up in Australia and PNG

More than a year after oil prices started to tank, it looks like the Australian and Papua New Guinea markets are poised for a period of serious merger and acquisition activity.

The latest round of maneuvering was kicked off in September by Woodside Petroleum, Australia’s biggest listed oil and gas producer, when it launched an A$11.6 billion ($8.4 billion) takeover bid for Papua New Guinea-based Oil Search. Woodside offered one of its own shares for every four held in Oil Search, which is also listed in Australia, in a proposal that the target and local analysts immediately dismissed as low-ball.

Woodside’s interest in Oil Search centers on its plum LNG assets, particularly its 29% stake in the over-performing PNG LNG project, operated by ExxonMobil. PNG LNG started up several months ahead of schedule in April 2014 and since then has exceeded expectations, operating at a rate of 7.4 million mt/year during the third quarter, well above its nameplate capacity of 6.9 million mt/year.

Oil Search is also a 22.8% stakeholder in Papua New Guinea’s potentially massive Elk-Antelope gas field, which is being appraised for development to feed the proposed Papua LNG project, operated and 40.1% held by Total. Papua LNG is also expected to produce from two trains, with a final investment decision on the project being targeted for 2017.

Woodside’s overtures, however, have been firmly rejected by Oil Search, whose managing director Peter Botten this week said the offer was “highly opportunistic” and “grossly undervalued” the company. Botten added that Oil Search’s board saw very few synergies with Woodside, with which it has no asset overlap.

Woodside CEO Peter Coleman has so far indicated he has little appetite to raise the bid, which valued Oil Search at A$7.65/share. Despite this, analysts have pointed to the possibility that the offer could be hiked to around A$9.00/share, or that another major, most likely ExxonMobil, could step in.

Market observers are also suggesting that should Woodside walk away from Oil Search, it could find a cheaper option in US-listed InterOil, owner of a 36.5% stake in Papua LNG. InterOil is currently capitalized at just under $2 billion and is also thought to be of interest to Papua LNG operator Total.

Meanwhile Santos, Australia’s second-largest E&P company, has become the subject of what would be one of the oil sector’s biggest-ever private equity takeovers. Investment fund Scepter Partners, which has links to the royal families of Brunei and the United Arab Emirates, on October 20 surprised the market by lobbing a A$7.14 billion offer at Santos.

The offer of A$6.88/share is regarded as a realistic opening salvo that is likely to lead to a deal being done, possibly in the region of A$7.50/share. At that price, Santos would be sold for around A$7.8 billion.

Like Oil Search, Santos has rejected the offer, but the company is in a weakened position, having seen its share price plummet from more than A$15.00 in early September 2014 to below A$4.00 on September 30 this year. The crash in oil prices has also meant Santos’ debt has ballooned, with analysts expecting it to top A$9 billion by 2016.

While side-stepping Scepter, Santos is pressing ahead with a strategic review that it launched in August. In addition to considering asset sales as part of the review, the company has so far announced plans to cut 756 employees from the 3,636 it had at the end of last year.

There’s also been an upturn in M&A activity among Australia’s junior players. This week Beach Energy and Drillsearch Energy unveiled plans for an all-scrip merger which would create a mid-cap oil and gas producer valued at around A$1.17 billion and with production of 12.1 million boe.

The deal, set to be completed next February, would combine the two companies’ overlapping assets in central Australia’s Cooper Basin, providing cost savings of around A$20 million annually.

Chinese interest has also emerged among local juniors. Landbridge, a privately owned Chinese group which in 2014 acquired Queensland-based coalseam gas company WestSide, earlier this month scuttled a proposed farm-in deal between Armour Energy and US shale pioneer Aubrey McClendon’s American Energy Partners.

Landbridge swooped on Armour with an A$0.08/share improvement on an initial A$0.12/share offer, securing the company’s acceptance for a total of just over $60 million. The offer swept aside an earlier agreement which would have seen AEP invest up to $130 million exploring Armour’s McArthur Basin tenements in central Australia over the next five years, with a view to earning a 75% stake in the massive area.

With those two deals all but done, interest is now centering on potential plays for other small onshore producers such as Cooper Energy and Strike Energy.

But the main game for now is Santos and the Papua New Guinea LNG sector. That’s where the big deals look to be coming.

ource: http://blogs.platts.com/

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