Brexit no deal is no worry for North Sea oil and UK energy sector

Economic warnings around a no-deal Brexit have reached fever pitch proportions. If Bank of England governor Mark Carney’s latest Doomsday portent comes to fruition, house prices will collapse and the streets will be choked by dole queues if the UK unceremoniously crashes out of the European Union. Certainly, the energy industry will also be affected; just don’t expect the petrol pumps to run dry, or the lights to go out on March 29 next year.

Based on the evidence at hand, the nation’s vital oil, gas and electricity industries can continue to prosper even in the hardest of hard Brexit scenarios. Firstly, losing jurisdiction over Britain’s oil reserves in the North Sea is theoretically bad for Europe because it pushes up the bloc’s dependence on imported crude from outside the region. The UK and non-EU member Norway currently account for 84% of all European production, according to the BP Statistical Review of energy.

Neither should a weak pound seriously threaten a strategically important industry, which uses the US dollar as its global currency de jure. Labor costs – among the offshore sector’s biggest overheads in the North Sea – should be kept in check by sterling’s depreciation against the greenback.

In terms of licensing and operating regulations on the North Sea, even the most brutal outcome to Britain’s protracted talks with Brussels would have little impact, say experts. “In the event of a ‘no deal’ outcome, the licensing and environmental regime relevant to upstream industry in the UK will remain broadly the same and that no action needs to be taken by UK or EU companies,” said Julia Derrick, oil and gas partner at law firm Ashurst.

However, the UK’s oil and gas producers remain mostly pessimistic about the prospect of leaving the EU. Their concerns are largely centered on higher operating costs and extra red tape. Shell – the largest oil major listed in London – warned this week about the added hassle of Brexit but this hardly constitutes a major problem for the company, or its shareholders.

“There’s no existential threat around Brexit,” said Shell’s country head Sinead Lynch. “There is however aggregation of additional costs, administration, complexity, which is completely the wrong direction when you think about what we are trying to do in the industry.”

Anyway, Lynch’s concerns hardly amount to a catastrophe for an industry which frequently has to adapt to the volatility of fickle oil markets. Nevertheless, industry group Oil & Gas UK has also warned a no-deal and reversion to World Trade Organization rules could add £500 million in trading costs. But for a sector expected to generate $920 billion of revenue through to 2035 these additional costs look irrelevant.

The group, which represents an industry employing over 280,000 workers, went on to argue that additional costs “such as those envisioned in a possible ‘hard Brexit’ scenario would be potentially detrimental to the ongoing international competitiveness of the UK continental shelf.” However, its own research suggests the North Sea has become one of the most efficient major oil producing basins in the world in terms of efficiency by reducing operating expenditures by around 43% over the last three years.

Net imports of crude, natural gas liquids and feedstocks totaled just 0.9 million metric tonnes in the first quarter of this year, one of the lowest levels since 2004, according to the Department for Business, Energy and Industrial Strategy. If this recovery keeps going then the UK in theory could eventually become a net exporter again, albeit briefly.

Oil storage is one area where, it can be said with certainty, will be affected by a juddering hard Brexit. This week the government advised Brexit could change the terms under which companies are obliged to hold stockpiles of crude so the UK can still meet its international obligations to maintain a strategic reserves. Cutting through the jargon, a no-deal Brexit may result in the UK requiring companies hold approximately 35 million barrels in storage under International Energy Agency rules, instead of around 76 million barrels under EU edicts.

In other corners of the UK energy industry the evidence to support negative consequences of a no-deal Brexit is thin. Although Britain imported 4.8 billion cubic meters of the fuel from continental Europe through underwater pipelines in 2017, those flows won’t be endangered by EU negotiator Michel Barnier holding the public’s feet to the fire. Power supply is also secure, with more underwater cables to transmit power across borders planned regardless.

Britain imports less than 10 percent of its annual demand from Europe, but also has the capacity to send electricity in the opposite direction. Over the last year demand averaged 33.8 GW, of which imports met less than 3 gigawatts of demand. The UK has 4 gigawatts of subsea cables installed and a further 4.4 GW are being built to France, Belgium and Norway.
A weak pound combined with a higher euro carbon price could also see UK exports of power increase – giving British thermal generators a last hurrah before 2025.

Even the most hardline Brexiteers cannot in all honesty expect the UK to leave Europe without suffering some economic consequences, at least in the near term. After all, it is entirely reasonable to prepare for the worst-case scenario when dealing with something that has never happened before. The energy industry – still Britain’s economic lifeblood – should be ready for all eventualities on March 29 but meeting demand for oil, gas and power should remain its most important priority regardless.

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Out-of-kilter Newcastle 6,000 NAR thermal coal prices put future of Asian benchmark in question

In Asia Pacific thermal coal circles it is known as the “great decoupling” and refers to the yawning gap between spot traded prices for Newcastle 6,000 NAR thermal coal and another grade of Newcastle thermal coal, 5,500 kcal/kg NAR.

That gap has blown out to an unprecedented $50/mt, from only $10/mt in early February, and the phenomenon has not gone unnoticed in wider business circles.

A September 12 report in the London Financial Times headlined “Why Asia needs a new thermal coal price benchmark” discusses this dramatic price gap and speculates that it might imperil existing benchmark indices for the 6,000 kcal/kg NAR grade.

Out-of-kilter Newcastle 6,000 NAR thermal coal prices put future of Asian benchmark in question: Thermal coal prices

Proponents of high prices for Newcastle 6,000 kcal/kg NAR coal insist supply of this specification remains tight due to underinvestment in Australia’s coal sector and recent industry consolidation. Others are unconvinced, pointing to the small number of spot trades for this grade at irregular intervals, and clustered around the time of Japanese contract price talks.

The price gap could be squeezed sooner than many expect, as Japan quietly moves to restart a number of its stalled nuclear power generators left idle since the Fukushima accident in 2011.

Newcastle 6,000 kcal/kg NAR benchmark prices also appear to have decoupled from market prices for other grades of thermal coal, including Platt’s NEAT coal index for Japan, South Korea and Taiwan, and which some would argue is a contender for Asia’s new price benchmark for thermal coal.

For NEAT, an index that tracks the price of cargoes delivered to Japan on a 5,750 kcal/kg NAR CV basis, the price differential to Newcastle 6,000 kcal/kg NAR prices is currently $30/mt, after hitting a high of $37/mt in August.

The NEAT price index is based on traded prices for the liquid Newcastle 5,500 kcal/kg NAR market, which is generally shipped to China, though cargoes have traveled to India, Turkey and Mediterranean Europe, plus indicated freight for Panamax ships on the Newcastle to Kinuura, Japan trading route.

The lift-off in Newcastle 6,000 kcal/kg NAR prices started in early May, around the time that annual price negotiations for deliveries of Australian shipments to Japanese power plants over the 2018-2019 Japanese financial year became intractable.

Instead of being wrapped up quickly in convivial meetings over tea in Tokyo, this year’s talks foundered amid a soured atmosphere as price negotiators for the largest buyer and seller of Australian thermal coal in the Japanese market were unable to agree a price for their April-year term contracts.

Eventually, the April talks were abandoned, and a benchmark deal was salvaged when two other Japanese power companies and their large Australian supplier agreed a price of $110/mt for shipments of Newcastle 6,322 kcal/kg GAR — equivalent to 6,000 kcal/kg NAR thermal coal — for the Japan’s fiscal year 2018-19.

Out-of-kilter Newcastle 6,000 NAR thermal coal prices put future of Asian benchmark in question: price differentials

The price differential between Newcastle 6,000 kcal/kg NAR prices and NEAT and Newcastle 5,500 kcal/kg NAR continued to expand through June to August as Chinese demand for high-ash Australian thermal coal slumped on import controls, and its price hit close to $60/mt FOB Newcastle.

How much longer prices for Newcastle 6,000 kcal/kg NAR thermal coal — the grade used mostly by Japanese power generators — can remain out of kilter with wider Asian market prices will have to be seen.

It is a multi-million dollar question, to which only the market can provide an answer. But, when it happens, the price correction could deliver a heavy blow to those with bullish market positions for Newcastle 6,000 kcal/kg NAR thermal coal.

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Will 2020 be a game changer for bunker credit?

The twin pressures of tough financial times for the shipping industry and the likelihood of more expensive fuel in 2020 are bringing the issue of bunker fuel bills into focus for the industry.

Many shipowners and operators have gone through difficult times since the global economic crash of 2008. There have been numerous bankruptcies, heavy losses, and the revaluation of assets on balance sheets across the industry.

This has not just affected small companies. Perhaps the most prominent failure of recent times was the Korean liner company Hanjin Shipping which some regarded as too big to fail, but which was ultimately declared bankrupt in early 2017.

2020 will be yet another pitfall for ship operators. Bunker fuel represents the most prominent voyage cost, and bills are set to increase substantially overnight, presenting a further stress point.

At present 3.5% sulfur, 380 CST fuel oil makes up the lion’s share of bunker fuel sales. Once the IMO’s sulfur cap of 0.5% comes into effect in January 2020 the majority of ship operators will have to turn to more expensive fuels such as marine gasoil and very low sulfur fuel oil to remain compliant.

Based on costs in July at the European bunkering hub of Rotterdam, this would mean a price increase of around $196/mt if a ship operator were to switch to MGO and $164/mt if they switch to 0.1% (ultra low) sulfur fuel oil.


A large proportion of bunker fuels sales are made on credit. Where this occurs, bunker sellers contribute to the working capital and liquidity of ship operators, and this financing has become an important part of the operators’ financial structure.

For sellers, 2020 is a huge shake-up of their business, not only in terms of products sold and bunkering infrastructure, but also from the perspective of credit. They will face a sudden and substantial increase in demand for credit from customers turning to more expensive fuels.

This could present a period of heightened customer credit risk, and also test their own resources as they are asked to finance the increased credit requirement.

It raises the questions, will the bunker suppliers and trading houses be willing, or even able, to finance this sudden credit demand shock?


Bunker sellers come in all shapes and sizes, ranging from oil majors and the largest independents, through suppliers and traders of varying means, all the way down to one man bunker trading businesses.

Understandably these players have differing capabilities, roles, and attitudes to risk. Given this, there are likely many different answers to the questions posed.

Those at the top of the bunker seller’s pyramid may continue to play it safe. The credit manager of a large independent supplier said their company had been increasing volumes with a top tier of ship operators, mentioning some top liner companies, dry bulk, and tanker operators. It had reduced business with a perceived riskier tier of small shipowners and operators.

2020 was a factor in this strategy, but was not the only driver. Difficult market conditions for bunker sellers had also dictated some revision of operations. Nevertheless, this supplier had already increased credit lines for the top tier operators with 2020 in mind. In some cases multi-million dollar credit lines had more than doubled.

An alternative perspective was provided by the credit manager of a bunker trading company. They acknowledged that 2020 could result in heightened credit risk, but thought that it was likely a short-term phenomenon. In the medium-term they envisaged that ship operators would manage to pass bunker costs to their own customers.

Credit management is a continual process and sales are monitored case by case, but the manager indicated that in the higher price environment special attention would likely be paid to the bottom 10% of the customer base, customers which were already making late payments.

It was not that credit would necessarily be cut for such customers, but perhaps that the trader would decline to increase credit lines initially. A suggested solution was to offer a mixture of credit and secured terms, but it was acknowledged that in the latter scenario the customer may prefer another provider that would offer credit.

The credit manager said it remained unclear what solutions its customers would be using in 2020, whether they would be using low sulfur fuels or utilizing scrubbers, and this meant that overall decisions about credit lines were yet to be taken. Some credit lines were increasing, but this was because bunker prices have been rising.

However, this company did have 2020 in mind. Its main focus had been on strengthening its own balance sheet, so that when the call for extra credit inevitably arrives it will be ready to provide it should it wish to.


For the last few years the bunker seller’s market has been characterized by intense competition.

In mid-2014 the price of oil plummeted and bunker prices soon followed. Low prices meant sellers of all types were able to stretch working capital further, and took advantage of this by aggressively chasing business. Further, the barriers for entry to the sector have remained low, encouraging more to join.

Broadly the result has been greatly diminished margins for all. To illustrate this, one source indicated that presently you might see 10 traders competing to stem one ship, and said about five years ago the margin for a single deal might be $10/mt, whereas today it could be a matter of cents.

This situation is viewed as unsustainable, and in this environment some sellers have experienced losses, and several have even had to reorganize operations.

Change could be coming, as high prices could conceivably alter competitive advantage among sellers. Bunker prices have already been trending upwards, placing more demand on seller’s working capital. This would only be intensified in 2020.

Returning to the bunker seller’s pyramid, those at the top will be best placed to meet the challenge, having greater existing resources to draw on, often sizeable bank credit lines in place, or being part of big organizations able to offer support.

Moving down the pyramid players may begin to see their resources stretched, but those at the bottom could suffer most. Higher prices could curtail their spending powers and reduce their competitive abilities.

We found this to be a common view among market participants we have spoken to. For some it would likely be a welcome development, but for others not so much.


The collapse of the bunker supply and trading company OW Bunker in November 2014 was a seismic event for the market. Some ship operators were caught in the uncomfortable position of having to pay for bunker stems twice in cases where OW had acted as a trader, once to OW’s bank, and again to the physical bunker supplier involved.

In the aftermath some operators chose to source bunkers directly from suppliers where possible, cutting out traders, and the perceived risk of exposure to a similar event. To this day where an operator uses a trader, it is understood to be quite common for them to ask for confirmation a supplier has been paid before paying the trader.

As bunker sellers could also feel some pressure from 2020, we asked our contacts if they thought operators may also be reviewing their suppliers. Those we spoke to thought it likely, but not necessarily for the same reasons as after OW.

The bunker supplier credit manager was of the view that many ship operators would opt to use a narrow range of bunker suppliers because of concerns over fuel compatibility, which will be a more pressing issue post 2020.

The bunker trader credit manager agreed this was possible, but thought that with their own balance sheets to think about, not all bunker suppliers would want to shoulder an increased credit burden alone.

On occasion bunker traders are already asked to insert themselves into a deal in order to be the credit provider. This was said to be high volume, low margin business, but was thought one way traders might offset a possible reduction of business.

Further, it was pointed out that many companies working in tramp trades or on projects will still require traders, so any thoughts of the demise of bunker trading are premature.

It was believed that given concerns about fuel compatibility ship operators would increasingly seek out trusted traders and suppliers, with the focus more on product and service quality, where it may have previously been on price. The current reports of contaminated bunkers were highlighted as a case and point.


We are only scratching the surface here, but it seems that bunker sellers will be prepared to increase credit lines for 2020, in some cases having done so already.

However, credit decisions continue to be judged case by case, and while there could be a more flexible credit scenario for the largest ship operators, there could be a more pressured environment for smaller, riskier market participants.

Inevitably, the largest bunker suppliers will be best placed to meet the increased requirement for credit. Small sellers are expected to come under pressure, as they may not have the resources to compete for the volumes they have managed in a low price market.

This could go some way to reshaping the bunker seller’s market, which some would welcome, especially if it alleviates low margins. Fuel compatibility and quality are also factors that could do this.

2020 doesn’t just present risk for bunker sellers and buyers: risks extend to the whole market. Everyone needs to pay attention to their counterparties, whether they are extending them credit or not. It pays to remain vigilant.

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Insight from Washington: What to watch for in the US midterm elections

By the time the polls close on November 6, Democrats may have wrested control of the US Congress for the first time since January 2011, an outcome which could have dramatic consequences for the future of Donald Trump’s presidency.

November’s US midterm elections could set the path forward for federal policy for years to come and are likely to set the tone for 2020’s presidential election.

While US oil and natural gas production is forecast to continue to shatter output records, something almost unthinkable back when Democrats last held control of the House and Senate, American energy policy is not expected to take a prominent role in these midterms. Still, voters will decide on a number of related policies, including a ballot initiative that opponents believe could stymie Colorado’s growing oil and gas industry and a push to repeal a gasoline tax in California, which may bolster demand in the country’s most populous state.

In addition, the future of oil and gas policy could become a factor in races in North Dakota, Texas and Florida.

Here’s what to watch for in the upcoming elections.

Colorado drilling

Colorado voters will decide whether to approve Initiative 97, a ballot measure that will increase land setback from new oil and gas development and hinder future output in the DJ Basin. Colorado is the seventh largest oil-producing state in the US and the sixth largest gas producer. If approved, the measure would require any new oil and gas development on non-federal land, including reopening plugged wells, to be at least 2,500 feet away from homes and schools. These new rules could cause Colorado oil production to drop by 50% within three to five years, predicted Dan Eberhart, CEO of Denver-based drilling services company Canary, in a recent interview with the S&P Global Platts Capitol Crude podcast.

California gas tax

California voters will vote on Proposition 6, which would repeal a tax increase approved by Governor Jerry Brown last year. The measure increased gasoline taxes by 12 cents per gallon and diesel taxes by 20 cents per gallon. The bill, which also raised vehicle fees, was designed to repair highways, roads, mass transit and other transportation projects. Proposition 6, if passed, would also require California voters to approve any fuel tax increase in the future, even if approved by state lawmakers.

Washington state carbon tax

Washington voters will decide the fate of Initiative 1631, which would set a fee, or tax, of $15 per metric ton on carbon emissions beginning in 2020. The fee, opposed by the oil and gas industry, would increase by $2 per ton each year plus inflation. If it passes, Washington would be the first state in the US to set a fee on carbon emitters. A carbon tax was defeated by Washington voters in 2016.

Races to watch

In North Dakota, where a statewide oil output record was recently broken, the race between Senator Heidi Heitkamp, a Democrat, and Congressman Kevin Cramer, her Republican challenger, could delve into the state’s future as an oil and gas producer.

In Florida, Senator Bill Nelson, a Democrat, has squared off with his Republican challenger, current Governor Rick Scott, over the Trump administration’s plans to expand offshore oil and gas production. Scott secured a pledge from Interior Secretary Ryan Zinke to keep oil rigs out of Florida waters, but Nelson has stressed this can be easily reversed. Interior officials said that all aspects of the offshore plan are still under consideration.

In Texas, the top producing state, Senator Ted Cruz, a Republican, is expected to face a fight over a number of energy policy issues with Congressman Beto O’Rourke, his Democratic challenger, over climate change action and reform of the Renewable Fuel Standard.

Election math

The US Senate currently has 51 Republicans and 49 Democrats, including two independents, and 35 seats are up for re-election in 2018, including 26 held by Democrats. Democrats will need to gain two seats to take control. The US House is currently made up of 237 Republicans, 193 Democrats and five vacancies. Democrats need to gain 25 seats in order to control the House. FiveThirtyEight, a statistical analysis website, forecasts that Democrats have nearly a 82% likelihood of winning control of the House.

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Could IMO 2020 sulfur cap be subject to law of unintended consequences?

The International Maritime Organization’s 2020 global 0.5% marine sulfur cap is an act of stewardship to protect the planet and human health for generations to come, but the supply and demand imbalances created by the cap encapsulate the law of unintended consequences.

The new sulfur cap is expected to displace around 3 million b/d of high sulfur fuel oil, according to S&P Global Platts Analytics. While the 2020 sulfur cap will endeavor to protect the marine environment and human health in an act of stewardship, the excess cheap high sulfur fuel oil sidelined from the bunker industry could prove attractive to nations trying to save on costs for power generation, such as Pakistan, Bangladesh and other East Asian countries.

The use of high sulfur fuel oil in power generation is unlikely to be anywhere close to the 300 million mt a year that the bunker industry currently chews through, but a significant price drop could make it attractive for Middle Eastern consumers to use heavy fuel oil to churn out air-conditioning at lower costs. This potential increase in heavy fuel oil consumption for power generation would likely be at the expense cleaner products such as LNG.

“I think cost is the main driver for energy options. In the absence of stringent environmental regulations, cheap and polluting fuels will certainly find a market regardless of their environmental impact,” Dr Yousef Alshammari, CEO of UCERGY Analysts, told S&P Global Platts.

Thus a protective initiative could have certain unintended consequences, as the drive for preservation following decades of industrialization and degradation by developed nations creates a headache for those looking at global supply and demand of traditional fossil fuels.

This amounts to a battle of price versus sustainability. Programs such as the United Nations’ Sustainable Development Goals need more focus in the energy industry, in combination with private funding, to assist industrialization in developing nations while discouraging the need to pursue cheap, heavily polluting fuels.

“Public-private partnership is always important in achieving development agenda,” Alshammari said.

It will not be long before the next environmental cap is imposed on the shipping industry and developing nations will be looking for new ways to benefit from the knock-on effects in their drive for economic growth and for consumer price protection. Consequently it will be a challenge to align international development with sustainable fossil fuel or renewables use on a mass scale.

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Midland WTI gets its own cavern at LOOP crude terminal

The Louisiana Offshore Oil Port has quietly allocated one of its eight underground crude oil storage caverns to West Texas Intermediate, a reflection of the Texas grade’s continued ascent as the US’ flagship oil.

In documents published to its website, LOOP established this month a “Midland WTI cavern” into which the grade may be delivered. LOOP defines Midland WTI as maximum 44 API, maximum 0.45% sulfur, maximum 10 psi RVP, maximum 11 psi TVP and maximum 1% sediment and water.

The cavern is known as Segregation 21. It replaces Segregation 20, which allowed for deliveries of maximum 46.5 API Eagle Ford, Bakken and Midland WTI. That took effect in October 2017. The cavern has historically been used for light grades. Before October 2017, LOOP in the past also allowed for the Nigerian grades Bonny Light (34.4 API, 0.20%S), Forcados (30.3 API, 0.18%) and Qua Iboe (36.3 API, 0.12%) to be delivered.

The best option for delivering WTI into LOOP would be via Shell’s 375,000 b/d Zydeco pipeline (formerly known as Ho-Ho), which extends from Houston to the Louisiana terminal. Another option would be by barge or tanker from Corpus Christi or the Houston area delivering into LOOP’s offshore platform. A typical river barge holds 10,000-30,000 barrels of oil, while new articulated tug-barges (ATBs) used on the ocean can hold as much as 340,000 barrels. Shippers can also rail crude to Genesis Energy’s Raceland, Louisiana, terminal, where it can be injected into pipe and reach LOOP.

The move reflects the rising importance of WTI globally. The Permian region of West Texas and southeastern New Mexico, from which WTI comes, is currently producing around 3.4 million b/d of oil, according to US government figures. The Permian accounted for 26% of total US oil production in 2017. Phillips 66 is a large regional consumer of light sweet grades at its 249,700 b/d Alliance refinery in Belle Chasse, Louisiana.

LOOP’s eight caverns hold about 60 million barrels in total, or roughly 7.5 million barrels each. LOOP currently lists assignments for six of the eight caverns. This includes Mars in two caverns, Thunder Horse, LOOP Sour, and Segregation 17, into which Arab Medium, Basrah Light and Kuwait may be delivered. The status of two caverns is not known.

LOOP is owned by Marathon Petroleum (50.7%), Shell (46.1%) and Valero (3.2%).

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OPEC’s lost decade

Ten years ago the global financial crisis exploded on Wall Street. The most violent and sustained economic eruption in living memory left no industry unharmed, energy included. Oil producers are still grappling with the debris thrown up by its shockwaves.

The damage was made worse because few oil policy makers saw it coming. In the summer of 2008, crude was trading at an eye-watering record $147/b. By the first week of September, OPEC was compelled to cut its production to defend prices even though a barrel was still trading above $100. A few days later, Lehman Brothers collapsed and the rest, as they say, is ancient history.

“Oil prices, by the middle of the year, soared to heights that were not only unimagined but, as well, unsustainable,” OPEC’s then secretary general Abdalla Salem El-Bari bemoaned in his official review of 2008. “Prices were to later come under unprecedented downward pressure as the financial crisis continued to sweep the world causing a contraction in global oil demand for the first time since 1983.”

By the end of that year, the cartel El-Badri headed had been forced into cutting a further 2.2 million b/d from its supplies, the biggest single output reduction in its 50-year history. Faced with a collapse in the value of oil as demand for their crude slumped, the group’s heavyweight Middle East producers had few other options if they wanted to keep their petrodollar-supported autocracies afloat.

Even then their response almost backfired. Two years later, political fires smoldering across the Middle East were partly kindled by the global economic downturn into a full blown inferno. These uprisings, which started as bread riots, became known as the Arab Spring. Attempts to manage oil markets in the wake of the crisis by striking a deal with Moscow also miscarried when the Kremlin backtracked on its promise to cut production.

These actions left OPEC – the controller of a third of the world’s oil supplies – open to blame for mismanaging the supply of the world’s most important resource. Some critics would even argue it had even played a role in starting the economic crisis in the first place for failing to act fast enough to reduce record-high oil prices.

Just a few months prior to Lehman’s juddering collapse, the group’s kingpin Saudi Arabia was being fiercely pressured by then US president George Bush and UK prime minister Gordon Brown to pump more oil as Americans were having to pay $4 per gallon for their gasoline. The Saudis trotted out their usual excuse and blamed greedy traders for causing an oil market bubble. Nevertheless, keen to avoid blame by their key Western allies they made a token gesture of adding an additional 220,000 barrels to daily supply. It was too little, too late.

Former Saudi oil minister Ali Naimi writes in his memoirs of the time: “We in Saudi Arabia realized that we would have to be the ones to break the oil market’s speculative fever”. Prices would eventually recover as a near $600 billion stimulus plan rolled out by the State Council of the People’s Republic of China triggered a commodities super cycle, which would see the world’s most populous country suck up ever increasing volumes of natural resources.

If the financial crisis came as a surprise to oil producers, its decade-long aftermath has showed them to be equally unprepared for the unexpected. The Federal Reserve’s actions to slash borrowing rates and flood the world’s largest economy and biggest consumer of oil with cheap money nurtured OPEC’s worst enemy. Extracting oil and gas from formations of tightly packed rocks in a process known as fracking had been around for years before record low interest rates made it possible for America’s so called “mom and pop” drillers to challenge the status quo of world energy.

In 2008, the US was producing a few drops under 5 million b/d of oil, with its domestic petroleum industry suffering years of decline and underinvestment. Next year, however, daily output is expected to near 12 million barrels after a decade of fracking, which has helped to turn America into an exporter of energy. Meanwhile, OPEC’s current daily production of around 32.9 million barrels is roughly where it was in the third quarter of 2008 before Lehman shut its doors.

None of this would have been possible without the flood of cheap debt pumped into the system following the financial crisis. According to research conducted by Amir Azar, a fellow at the Center on Global Energy Policy, net debt held by investment grade exploration and production companies in North America ballooned by 730% between 2005 and 2015.

“The real catalyst of the shale revolution was thus the 2008 financial crisis and the era of unprecedentedly low interest rates it ushered in, driven by the US Federal Reserve Bank’s monetary policy. American entrepreneurship, coupled with low-cost debt, created the conditions for a surge in production that ranks among the biggest oil booms in history,” wrote Azar.

This bond-fueled drilling bonanza eventually led to another downturn in oil prices, which started almost four years ago as global supply growth outstripped demand. OPEC is still dealing with it today. The group was forced into an unprecedented alliance with Russia and its allies to reduce supply by 1.8 million b/d to rebalance the market. Their pact is likely to be enshrined in a new charter when they meet for their final summit of the year in December.

Meanwhile, the industry as a whole has shrunk. In 2014, spending peaked at $900 billion. This year, the figure is expected to be closer to $500 billion.

A decade later and OPEC is still dealing with the aftershocks of the financial crisis.

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Asia bunkering industry preparing for IMO 2020 sulfur deadline: Fuel for Thought

From Cosco in China to Posco in South Korea, Asian companies are pouring in millions of dollars to upgrade their shipping fleets as the International Maritime Organization’s deadline for cleaner bunker fuels inches closer.

With less than 16 months remaining, the global shipping industry is setting aside about $60 billion to obtain the right infrastructure in order to embrace cleaner shipping fuel.

The IMO’s global fuel sulfur cap is set to drop from 3.5% to 0.5% at the start of 2020, forcing shipowners to make changes. While it’s evident that measures being adopted by most point to essentially three main options—the use of new low-sulfur fuel oil, instillation of scrubbers to continue use of high-sulfur fuel oil, or changing fuel to LNG—each alternative comes with its own set of challenges.

Cosco Shipping has stepped up orders for engines that allow dual-fuel operation, and steelmaker Posco has signed an agreement to get scrubbers fitted on bulkers delivering commodities.

South Korea’s Hyundai Merchant Marine said in April it was considering using LNG bunkers or installing scrubbers in its newbuilding of 20 mega container ships.

In May, container shipper APL, a part of CMA CGM Group headquartered in Singapore, said it was considering an array of bunker fuel options—including scrubbers—to comply with the rule.

Taiwan’s Yang Ming Marine Transport Corporation in July said the use of low-sulfur fuel was the intended solution, but it couldn’t rule out other options.

More recently, Hong Kong’s Pacific Basin Shipping said it was assessing two main methods of compliance, weighing low-sulfur compliant fuel oil versus scrubbers.

Compliance to the sulfur rule is expected to be high, with some estimating it to settle at 80%-90% in the initial years after 2020 as increased public awareness and growing enforcement spur more investments to switch to cleaner fuels.


In an ideal world, the easiest and simplest way to comply with the new regulation would be switching to 0.5% sulfur fuel; however, a lack of availability for the new fuel could stand in the way. And until a standard set of specifications is agreed upon, the 0.5% sulfur bunker market is expected to be chaotic.

In August, Shell Global Marine Fuels Network said it started testing its new 0.5% very low sulfur marine fuel oil, or VLSFO, in preparation for the IMO 2020 rule. The company said it successfully completed initial trials for the blend, and tests were available at several locations, including Singapore, to shipowners and charterers purchasing fuel with Shell.

ExxonMobil said in June it is proposing a multi-billion dollar expansion at its integrated manufacturing facility in Singapore to produce higher-value products. The expansion will result in production of fuels that comply with the IMO sulfur cap, it said, without elaborating on fuel specifications.

Other refiners are taking steps in this direction, but there are questions around using blended fuels because of concerns surrounding stability and compatibility.

The use of blended fuels could cause problems like sludge formation in fuel tanks, cat fines, blocked filters or even engine failure, adding to shipowners’ woes and maintenance costs.


It’s becoming more evident the adoption of scrubbers to clean engine exhaust is set to spike in response to meet the new standards as economics turn favorable, reflecting shorter payback periods as more manufacturers sprout and the cost of the technology falls.

Drewry Maritime Financial Research projects the premium of LSFO over HSFO will fall from $300/t in 2020 to $87/t by 2023, and, accordingly, the savings on bunker cost for a modern eco-VLCC will decrease from $5.7 million to $1.6 million.

For VLCCs, the cost of fitting an open-loop scrubber in a newbuild ship is around $2.5 million-$3 million, whereas the cost of retrofitting a scrubber on an existing VLCC is estimated to be about $4 million-$4.5 million.

This price trend suggests owners opting for scrubber-fitted vessels in 2020 will recover their cost in the first year alone, Drewry added.

Still, a fair amount of uncertainty shrouds widespread scrubber adoption.

Scrubbers have been mostly used by cruise liners and short sea ferries, not large container ships.

Operating in open-loop mode, scrubbers remove pollution from exhaust gases then flush it into the sea instead of into the atmosphere. Operating in closed-loop mode, scrubbers retain the pollution in tanks on board the ship, a practice not practical for long-distance journeys.

There is the risk regulations could change in coming years and would prohibit flushing the pollution into the sea.

Availability of HSFO for scrubber-fitted vessels, particularly at small ports, could also be restricted if the overall fleet of scrubber-fitted ships remains small, as there will be a cost associated with maintaining inventory of a less-popular fuel.


Hurdles also remain on the widespread adoption of LNG as a cleaner marine fuel.

Expense is a huge sticking point.

According to some industry sources, the cost of retrofitting an existing VLCC with a dual-fueled
engine would be much higher than installing one on a new build, which would potentially cost well over $15 million.

In addition, LNG engines and fuel tanks typically take up much more space than their conventional equivalents, and would likely cut down the amount of cargo a vessel can carry.

Lack of adequate crew training and concerns over the fuel’s safety have also been cited as hurdles to foster its use as the chief marine fuel.

And as shipowners are considering their options on tough, expensive decisions, refiners, bunker traders and suppliers also have to adapt to the changing industry dynamics fairly quickly.

While there might be some initial hiccups, the shipping industry is thought to be quite resilient to change.

The IMO has reiterated time and again there is no possibility of delaying the rule, and the importance of coordination among the different stakeholders becomes even more vital in such a scenario to ensure a level playing field for all.

The post Asia bunkering industry preparing for IMO 2020 sulfur deadline: Fuel for Thought appeared first on The Barrel Blog.


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