Maduro’s squandering of Venezuela’s oil wealth is a tragedy

Venezuela should be a global oil-exporting superpower. Instead, the Marxist junta ruling the country teeters on the brink of complete economic collapse, with hyperinflation reminiscent of Weimar Germany and the chances of a political coup d’état in Caracas rising every day.

Despite its enfeebled state, Venezuela punches above its weight in oil markets. Uncertainty over its supply has helped to push up prices by almost 20% since the start of the year. That’s because many refineries in Texas and Louisiana – America’s fuel-producing engine – are configured to process Venezuela’s heavy blend of crude.

The country supplies about 50% of the oil used by the southern states’ plants dotted around the Gulf of Mexico. Finding suitable alternatives at short notice won’t be easy.

“Crude oil production in Venezuela, and especially exports to the US, are expected to drop in response to the growing political crisis and the US implementing new sanctions against its state-run oil company, PDVSA,” said Ole Hansen, head of commodity strategy at Saxo Bank.

Go deeper – Factbox: US sanctions on PDVSA, accelerate output decline

Daily shipments to the world’s largest economy have slumped below 500,000 barrels, down from over 1.2 million b/d a decade ago, according to the Energy Information Administration. US President Donald Trump’s decision to slap punitive sanctions on state-controlled oil giant PDVSA is a further economic hammer blow aimed at Nicolas Maduro, his Venezuelan counterpart.

The embargo comes at a tricky time for oil markets and consumers. Saudi Arabia is pushing its partners in OPEC to implement deep output cuts the cartel agreed last December in order to boost depressed global prices. Venezuela is a founding member of the production group, which in alliance with Russia controls around 40% of world oil supply. Venezuela signed OPEC’s original charter in Baghdad in 1960 alongside Iran, Iraq, Saudi and Kuwait.

Back then, Venezuela’s people were among the most prosperous on the planet.

This year, Venezuelan oil minister and Maduro loyalist Manuel Quevedo is due to take over the revolving presidency of OPEC – traditionally an important role for coordinating among the cartel’s 14 members. However, his status grows ever more uncertain as opposition leader and self-appointed alternative president Juan Guaido draws throngs of disgruntled supporters to his cause.

Although Guaido’s “shadow government” lacks control of the military and a legitimate cabinet of ministers, the 35-year-old leader of the National Assembly has moved swiftly in his attempt to seize control of the nation’s crucial oil riches. He ordered congress this week to nominate a new board of directors at PDVSA and its US refining subsidiary Citgo.

US sanctions will help his strategy by choking off Maduro’s access to oil revenues, the president’s final source of income to prop up the regime. US Treasury Secretary Steve Mnuchin said last week: “If the people in Venezuela want to continue to sell us oil, as long as the money goes into blocked accounts we will continue to take it.” However, sanctions could prove sensitive if a spike in prices pushes up the cost of gasoline for American motorists, a raw nerve for the grassroots supporters of Trump’s government. Analysts agree regime change could still take months.

“The Trump administration appears to be making a major bet on squeezing Venezuela economically to accelerate regime change, which for the oil industry could eventually bring sanctions relief, foreign investment, and a return to production growth. But this ultimately hinges on co-operation from the Venezuelan military, the leaders of which continue to publicly support Maduro despite signs of cracking at lower levels,” wrote S&P Global Platts Analytics in a research note.

Sanctions have had mixed results for Trump elsewhere. Legislation introduced last year targeting Iran raised concerns in the market about potential supply shortfalls until the US introduced temporary waivers for several major customers of its crude. However, these dispensations will expire soon, further tightening an already constricted oil market and potentially pushing up prices.

Maduro may also find an ally in Russia’s President Vladimir Putin. Venezuela gives Moscow access and influence in America’s back yard.

“The duration of the sanctions regime will ultimately hinge on Maduro’s staying power and Moscow could play a critical role in determining the trajectory of the crisis. Russia has extended multiple, multi-billion dollar financial lifelines to the country, enabling the cash strapped national oil company to avoid a catastrophic default that would have resulted in asset seizures by creditors,” warned Helima Croft, head of commodity strategy at RBC Capital Markets in a research note.

Venezuela’s oil industry has suffered a staggering decline of fortunes over the last 20 years amid chronic mismanagement, systemic corruption and continual political acrimony. Its proven reserves are by some measures thought to be the world’s largest at almost 300 billion barrels. By comparison, Saudi Arabia holds just under 270 billion barrels. Venezuela’s total petroleum reserves could be much greater, especially in its rich Orinoco basin.

In theory, a new government could turn things around quickly. Reform of the oil sector would deliver an economic dividend and a boost to supply. But unless the country can attract investment from international oil companies its potential will be constrained. Resource nationalism remains a potent political totem on the streets of Caracas.

Despite its embarrassment of oil riches, Venezuela’s economy is in free fall. The IMF estimates that GDP has collapsed by 50% since 2013. Meanwhile, oil production – its main source of hard foreign currency earnings – has plummeted. “Hyperinflation and outward migration are also projected to intensify in 2019,” said the fund in its latest assessment of the region’s prospects. “Evolving political developments add another layer of uncertainty to the country’s outlook.”

Output will now keep falling because of sanctions pushing up the cost of production. S&P Global Platts estimates total daily output could drop to 1.15 million b/d – a decline of 175,000 – by the end of the year. A separate survey of OPEC output conducted recently by Platts paints an even bleaker picture with Venezuela pumping just 1.17 million b/d in December.

Maduro’s regime has no means of replacing this lost revenue and instead faces a slow and agonizing death by economic strangulation. Instead of being among Latin America’s most prosperous nations, Maduro has unleashed a catastrophe on his own people. His failure to take advantage of Venezuela’s wealth in natural resources is nothing short of a tragedy.

This article previously appeared as a column in The Telegraph.

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And the honoree is…Maria Mejia, Senior Vice President & CFO of @UlterraBits. Join us Feb. 12, at the Hilton Americas – Houston as we honor 25 influential leaders in our industry. To view the program:  #OGIwomeninenergy

And the honoree is…Maria Mejia, Senior Vice President & CFO of . Join us Feb. 12, at the Hilton Americas – Houston as we honor 25 influential leaders in our industry. To view the program: 


Insight from Brussels: Renewables win in new EU power market design

Renewables are the big winners in the European Union’s new power market rules, which are designed to help the grid cope with ever increasing shares of variable sources such as wind and solar.

This is part of the EU’s long-term push to cut its greenhouse gas emissions and reduce fossil fuel imports.

At the end of 2018 it adopted a binding target to source at least 32% of its final energy demand, including heating and transport, from renewables by 2030.

That translates into sourcing more than half its electricity from renewables by 2030, up from around 30% today, and that upwards trajectory will only continue as the EU seeks to decarbonize its economy by 2050.

The EU’s new power market design regulation, which is expected to become binding in 2019, aims to create a flexible, responsive and integrated grid, able to cope with renewable inputs that vary hugely from day to day and from country to country.

In Denmark, for example, which has for years invested heavily in wind, the share of renewables in its power output varied from zero to 100% within 2017, according to formal EU power grid operators’ body Entso-e.

That worked out as around 70% on average for the year for Denmark, compared with well under 50% for most of the rest of the EU.

Overall, the EU still sources 70% of its power from non-renewable sources, and this 70:30 ratio has “remained broadly consistent” over the last three years, Entso-e said this year.

The new power market rules are intended to help renewable power grow, and support the flexibility options needed to cope with more variable output. For example, the rules retain priority dispatch for existing renewable power plants, but allow transmission system operators to curtail output from new renewable power plants.

TSOs will also have to report on all redispatch actions – interventions in the expected priority order of different generation assets to balance the grid. They will have to follow recommendations from regulators on how to be more efficient in their redispatch, and avoid curtailing renewables.

“This will help give transparency on any ‘must-run obligation’ agreements with conventional power plants that are crowding out renewables from the grid,” trade body WindEurope said.

The solar sector is also delighted with the new rules, in particular for securing “the uptake of small scale and locally owned solar installations” in the EU, its trade body SolarPower Europe said. This “will pave the way for a new solar boom in Europe.”

CO2 limits for power plants

One of the most controversial parts of the new rules centered on emission limits for power plants taking part in national capacity remuneration mechanisms. Such mechanisms, which pay power plant operators to keep capacity available, are becoming popular with many EU governments worried about long-term electricity supply security in markets dominated by variable renewables.

The final deal – like all EU energy policy – is a compromise between what the European Commission, the executive arm of the EU, wants, and what national governments are willing to accept.

The EC was keen to ensure that governments did not use such mechanisms to support power plants with high carbon emissions, such as coal and lignite, and in this it partly succeeded.

Plants starting up after the power market design regulation enters into force – likely to be around mid- to late-2019 – with emissions higher than 550 g CO2/kWh will not be allowed to take part in capacity mechanisms or receive capacity payments.

Existing power plants emitting both more than 550 g CO2/kWh and more than 350 kg CO2 on average per year per installed kW will only be able to receive capacity payments until July 1, 2025.

These criteria impact all unabated coal and lignite power plants, which have emissions well above 550g CO2/kWh. They mean that existing unabated coal and lignite plants will only be eligible to receive capacity payments beyond July 2025 if they run for very limited hours to stay under the yearly average emissions limit. And new unabated coal and lignite plant coming online after 2019 will not be eligible for any capacity payments.

But there is an important exception. National governments will not have to apply the new emission limits to commitments or capacity contracts concluded before December 31, 2019.

This means Poland, which relies heavily on coal-fired power, was able to grant a 15-year capacity contract to the planned 1 GW coal-fired Ostroleka C power plant in December. Ostroleka is expected online in 2023, which means it will be allowed to receive capacity payments until 2038.

Polish energy officials have said this will be Poland’s last large coal plant, and that renewables will be the new focus. Poland aims to source 27% of its electricity and 21% of total final energy demand from renewables by 2030, according to its first draft integrated national energy and climate plan.

All EU governments have had to prepare such draft plans showing how they intend to help the EU meet its 2030 targets. The EC is to review them to ensure they collectively meet the 32% EU target, as well as the 32.5% energy efficiency improvement target.

That means 2019 will see a long negotiation between the EC and national governments over who should do what on renewables. But the trajectory remains clear – more renewables, less fossil fuels.

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New projects, cost-cutting efficiencies driving US Gulf comeback: Fuel for Thought

Activity in what has been a mostly sluggish US Gulf of Mexico is expected to increase modestly in 2019, bringing production growth and more exploration aimed at finding the elephant fields of the future.

Brent crude has fallen $20 from highs in the mid-$80s/b months ago, but US Gulf operators, especially in deepwater, aren’t phased by volatile prices, analysts say. Instead, operators are deciding to grow in the gulf because of the industry’s increasing ability to make those fields more economic.

Logistical and operational efficiencies, lower oilfield service costs, scaled designs and better engineering have combined to make the region more profitable than it was even before the 2014 industry downturn.

“Generally, when industry is at peak efficiency and operating at its best, industry fundamentals aren’t bad and oilfield costs are relatively low,” said William Turner, a Gulf of Mexico analyst at energy consultancy Wood Mackenzie.

US Gulf exploration and appraisal wells to rise in 2019

2019 will mark the first increase in US Gulf exploration in four years, Turner said. About 21 or 22 exploration and appraisal wells are expected this year in the US Gulf, up from 19 last year, according to Wood Mac. That compares with 40-50 wells drilled three or four years ago.

The increase is “from a low base,” Turner noted. “Certainly, we’re not at 2014 levels of exploration.”

The US Gulf accounts for nearly 16% of the US’ roughly 11.5 million b/d of oil production. Its crude oil production averaged 1.8 million b/d in Q4 2018, according to the US Energy Information Administration, compared with just less than 1.25 million b/d in 2013.

The EIA projects US Gulf production will crack the 2 million b/d mark in about a year. Meanwhile, S&P Global Platts Analytics projects oil output will end 2022 at 1.82 million b/d, up from a recent low of 1.50 million b/d in December 2018.

US Gulf of Mexico oil production poised for growth

Deepwater US Gulf spending is projected at about $10 billion this year, about the same as in 2017 but down from $16 billion in 2015, according to Wood Mac data. Contributing a swath of this year’s production will be Shell’s Appomattox field, capable of producing 175,000 barrels of oil equivalent per day at peak. Chevron’s Big Foot field, which debuted in November 2018, will ramp up this year; its peak production is 75,000 b/d of oil and 25,000 Mcf/d of natural gas.

Go deeper: S&P Global Platts Rigdata provides timely information on drilling activity in the US, Gulf of Mexico and Western Canada

Several smaller fields are due to come online in 2019, including Buckskin, Stonefly and Nearly Headless Nick from LLOG Exploration, with a combined production of 40,000-50,000 b/d.

Growing small operator Talos Energy, which acquired Stone Energy last year, said wells will come online this year at its Tornado and Boris field. The Tornado #3 well will debut at 10,000-15,000 boe/d, while Boris #3 should contribute 3,000-5,000 boe/d.

Better technology

Despite uncertain oil prices, enthusiastic operators say improved technology makes the area economic. Last month, BP outlined new US Gulf discoveries and nearly 1.5 billion additional barrels of oil it uncovered using improved seismic technology at its giant Thunder Horse and Atlantis fields. And Hess Corp. showcased numerous tieback opportunities at 50% to 100%-plus return rates during a December analyst meeting.

This year’s exploration plate will also see Hess spudding Esox, its first US Gulf exploration well in years, while Chevron already has a rig in place to drill the Yarrow prospect in the Mississippi Canyon area, south of Alabama.

Oil breakevens in the US Gulf average around $55-$60/b, Wood Mackenzie’s Turner said, although some projects are lower. Shell said its Vito development, which is slated for first oil in 2021, has a breakeven price less than $35/b.

Maintaining efficiencies

While tiebacks to existing fields will comprise a major part of US Gulf work this year, the big challenge is to “squeeze the efficiencies they’ve achieved and maintain them,” S&P Global Platts Analytics analyst Sami Yahya said. “What’s really important is the confidence of the market to maintain oil prices,” Yahya said. “They can’t sanction projects without fully knowing they can survive in a low-price environment.”

In addition, 2019 may see a significant project sanction: Chevron-operated Anchor in the Green Canyon area offshore Louisiana. Anchor is an early 2015 oil discovery the company at the time described as “significant.”

Anchor is not only important reserve-wise, but success and invocations there could open development opportunities across the industry, analysts said.

The field is ultra-high-pressure—20,000 pounds per square inch—compared to a current produceable limit around 15,000 psi. Technology is advancing to produce 20K fields, but few operators are large or able enough to take on the gamble.

If Chevron green-lights Anchor, which could happen by mid-year, it could open the frontier play to industry. That might result in a “gold rush” of new leasing and investment in remote, deep and technologically complex fields, Wood Mackenzie’s Turner said.

Another potential hot spot is the Appomattox field, which represents the first output from the Norphlet play offshore Alabama and Mississippi. Depending on how it performs, Appomattox could spur more Norphlet activity, analysts said.

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Upper Midwest gas market finds role as crossroads of America

The Upper Midwest market has become the crossroads of America for natural gas, and finding that sweet spot helped the region get through a record-breaking freeze without breaking the bank.

Chicago demand reached an all-time high of 10.65 Bcf January 30, but cash prices in the region experienced a decline as inflows ramped up to add bearish sentiment.

At the same time, inflows to the Central region increased by approximately 1.04 Bcf on the day to 16.3 Bcf, according to Platts Analytics. The last time inflows to the region were greater was February 27, 2015, when they were 16.49 Bcf.

The cash price for Chicago city-gates fell $2.43/MMBtu to $4.995/MMBtu January 30.

The bearish sentiment can be connected to robust inflows from the Northeast, the Rockies and Western Canada. Last year the response to a period of high winter demand was very different. Chicago city-gate sat at $9/MMBtu on January 2 2018. At that time, Chicago demand was approximately 9.89 Bcf, about 76 MMcf lower than the new record high of 10.65 Bcf, according to Platts Analytics.

When Chicago city-gate reached the $9/MMBtu last year, inflows from the Northeast into the Upper Midwest were 2.03 Bcf. By comparison, Northeast inflows were 4 Bcf when Chicago demand reached the all-time high.

The jump of inflows from the Northeast year on year is largely due to the buildout of Nexus Gas Transmission and Rover Pipeline, both of which move gas to the Upper Midwest from the Northeast.

The first to come online was Rover Pipeline, which went into service in September 2017. That pipe was averaging flows into the Upper Midwest of 1.3 Bcf/d last January. So far this year, flows on Rover from the Northeast into the Upper Midwest have averaged 3 Bcf.

The Nexus Gas Transmission pipeline came online in October 2018 adding even more downward pressure to the Upper Midwest market. Flows from the Northeast to the Upper Midwest on Nexus have averaged 650 MMcf/d this January.

Rockies Express Pipeline takes gas from the mountains into the Upper Midwest. On January 30, those inflows on REX sat at 1.05 Bcf – the highest levels since totaling 1.1 Bcf on November 6.

Inflows from Western Canada also ramp up in times of high demand in the Midwest. Volumes transported via the Viking Pipeline increased 48 MMcf on the day to 451 MMcf on January 29. That marked the highest level seen since flows on Viking were at 475 MMcf on December 31, 2017.

Looking forward, the Upper Midwest market is positioned so that any demand spike can be mitigated by an influx of supply from several regions. As production increases in surrounding regions, that gas should find its way into the Midwest and alleviate volatility.

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UK electricity links to Europe multiply, even as Brexit looms

This week marks the start of a new phase in London-Brussels relations. But it has nothing to do with Brexit, and it won’t be political power returning to Westminster as a result of the UK’s departure from the European Union.

Instead, the power flowing across the English Channel will be of the electrical variety, as the Nemo electricity interconnector – the first direct connection between the UK and Belgium – begins commercial operations on 31st January. The 1 GW link will be capable of supplying enough power to meet the electricity needs of 2.2 million UK homes.

Nemo is the first new interconnector between mainland Europe and the UK in 7 years and the timing of the link’s start-up is loaded with irony. Just as the UK is on the brink of severing its political connections with the rest of Europe, Nemo marks the first of a number of new planned subsea electricity interconnectors that will bind the UK more closely to Europe’s power markets than ever before.

Until now, the UK has had just two means of exchanging power with mainland Europe – the 2 GW IFA interconnector with France, which first came online in 1986, and the 1 GW BritNed interconnector with the Netherlands, connected in 2012. It also has 1 GW of interconnection with the island of Ireland – which since 2007 has operated as a Single Electricity Market (SEM) that unites Northern Ireland and the Republic of Ireland. Here too, electrical union has proved more palatable than political union, though a ”no-deal” Brexit requiring a ”hard” border between the north and south of the island would jeopardise the future of the SEM.

Go deeper – Outlook 2019: UK power hits peak uncertainty

But Nemo marks the start of a new wave of interconnector projects – with a host of new subsea cables to countries including Germany, Norway and even Iceland at various stages of the planning process. In total more than 30 GW of new interconnection capacity between the UK and its neighbours has been proposed – enough to meet more than 50% of peak demand. Platts Analytics forecasts just 8GW of this will be built between 2019-2025, as the chart below shows. But this still represents a trebling in interconnection capacity vs pre-Nemo levels.

GB electricity interconnector capacity to Europe set to soar

UK as premium market

Historically the UK power market has been priced at a premium to its mainland European counterparts, meaning that power has generally flowed from France and the Netherlands to the UK via the IFA and BritNed cables respectively. The premium in the UK is partly a reflection of its more expensive generation mix – with a greater proportion of coal and gas than France’s nuclear-dominated capacity mix.

But a bigger factor in recent years has been Britain’s Carbon Price Support (CPS)– currently set at £18/metric ton of CO2 equivalent. The CPS, introduced in 2013, is a tax that applies to carbon-emitting generators in Great Britain – it excludes Northern Ireland.  The tax is in addition to the cost of carbon allowances under the EU-wide Emissions Trading Scheme, currently priced at around €23/mt for the December 19 contract. The CPS is set to remain in place until at least 2021, while the UK government has said that in the event of a no-deal Brexit –  which would require the UK to leave the EU ETS -it would impose a further £16/mt carbon tax to keep the total carbon cost for GB generators broadly unchanged from 2018 levels.

S&P Global Platts Analytics expects that the UK power price will retain its premium to Belgium until the middle of the next decade, and that the Nemo interconnector will flow power from Belgium to the UK on a net average basis. In summers, when the discount in mainland European power prices to their UK equivalent is typically widest, we assume Nemo flows at its full 1GW capacity into the UK. This should put further pressure onto the profitability of UK thermal generation.

S&P Global Platts Analytics forecasts clean spark spreads – a measure for gas plant profitability – for summer 2019 (Q2+Q3 2019) at only £0.6/MWh, or £2.2/MWh below summer 2018. Further interconnectors – including the 1 GW ElecLink connection with France, scheduled to start in early 2020, will weigh even further on UK gas and coal plant profitability in the coming years.

Coal has already largely been priced out of the market in UK summers. Generation has fallen by 95% in the last five years to just 0.6 GW in Summer 2018 and is forecast to fall to just 0.2 GW in Summer 2019. Platts Analytics forecasts that gas generation will fall by 2 GW (or 17%) year-on-year in Summer 2019 to 10GW, due to a combination of increased imports and an assumed 1.2GW increase in wind generation vs Summer 2018.

Winter risk

While we expect the UK to consistently import from Belgium in summers, the story is more nuanced for winter periods. On average the UK has imported from mainland Europe in winters too, and Platts Analytics expects this to continue under normal conditions. But recent months have shown the vulnerability of Belgian power prices to severe spikes, largely due to the unreliability of the country’s nuclear fleet. The ageing Doel and Tihange nuclear reactors have suffered a series of extended outages in recent years and problems this winter saw Belgian power prices rise to record highs.

Under such circumstances the UK would have been exporting at maximum to Belgium if Nemo had been online, and as recently as December, forward spreads for February 2019 indicated that the first month of Nemo’s operation would see the UK exporting to Belgium as a result of the latter’s nuclear supply issues. However, these issues have since subsided as plants have returned online and the UK-Belgium price spread has recovered to positive, implying UK imports from Belgium. Platts Analytics forecasts an average 0.2GW of imports to the UK via Nemo in February.

But on January 29, Engie, the operator of Belgium’s Doel and Tihange nuclear plants announced a revised outage schedule that would see Tihange 1 (1.0 GW) and Doel 1&2 (0.9 GW combined) offline for most of next winter. Another winter of heavy nuclear outages in Belgium would sharply lift the probability of Belgium, and potentially France, needing to pull on the UK for power at times of high demand. So while the startup of Nemo should on average push UK prices down, we also expect the risk premium for Belgian winter power prices to decline as the market has another potential source of power in the event of another supply crunch. In other words, Nemo is a win-win story of integration for Europe’s power markets. Now, about Brexit…


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China’s quest for cleaner skies drives change in iron ore market

The iron ore market’s structural change last year is all to do with the environment, and led by demand patterns in China.

Iron ore with a higher content of iron, Fe, allows a reduction of coal usage in the steelmaking process, lowering carbon emissions. So trade has shifted away from the standard 62% Fe-quality base – the traditional iron ore benchmark product – to a multi-tier market. This includes specialty products that may be tailor-made for specific steel mills, with premiums, penalties and spreads between product values quite the order of the day.

“We’re carving the market up into segments: more and more we’re talking about high and low grade,” said Alex Griffiths, principal analyst, steel and iron ore markets with Wood Mackenzie.

Until late 2016, analysts note, there was no premium for the iron units in iron ore fines with a 65% Fe content. In July last year, with demand for high-grade iron ore soaring, the premium for these units leapt to 37% above the 62% grade price, slipping back to 16% at year-end.  The basic 62% commodity grade no longer calls the shots.

Has iron ore “decommoditized”?  Peter Poppinga, ferrous and coal executive director of Vale, the world’s biggest iron ore producer, says the move reinforces a point he has been making for some time. “Iron ore was never a commodity,” he said on the sidelines of the Vale Day in London early December. What has changed is that “now we’re getting the premium for quality” in a market that has “differentiated itself”, he said.

Structural change here to stay

The structural change is here to stay. At the start of 2018, a year in which governments, companies and the public alike speeded up action to combat climate change, steelmaking raw materials markets were impacted by China’s introduction of a severe winter cuts regime, curbing sintering, steelmaking and coal usage to cut back on smog  in selected locations  in a “blue sky” policy. This is set to become an annual event.

With new “cleaner” capacity coming on stream, China’s overall crude steel production has nonetheless continued to grow. However, the emphasis on quality in raw materials usage is producing a less carbon-intensive steel, with positive margins emerging due to the more efficient installations.

The cuts dispelled discussions that China was somehow not “serious” about its elimination of polluting steelmaking capacity. In March Beijing was ahead of schedule in its planned elimination of 150 million metric tons capacity between 2016-2020. This followed permanent removal of an additional 140 million mt of mainly illegal induction furnace capacity in 2017. Mergers and acquisitions relocated mills from smog-prone areas. The European Union’s emissions trading market and related controls have contributed to this trend.

China’s cuts reduced the market for the nation’s own iron ore, high in impurities and in cost: at least half of China’s previous 300 million mt plus iron ore mining capacity has left the market for good.  “We forecast an additional 30 million mt of seaborne iron ore imports to China over the next two years, largely weighted towards 2019 and mainly from Vale’s S11D,” WoodMac analysts said in a mid-December report, referring to the company’s Brazilian mining megaproject.

The 1.6 billion mt/year seaborne trade is also changing. According to Neelix Consulting mining and metals senior partner Jose Carlos Martins, this market is made up of 500 million mt/year of low-quality, mainly hydrated material, much of which has entered the market over the last ten years from Australian mines, with a high Loss on Ignition (LOI) – a measure relating to ore oxide analysis – and various impurities, with sheer quantities of new capacity production provoking price volatility.

Much of the rest of the market has become a pick and choose affair. Chinese and other buyers are seeking not only higher Fe content but qualities including low alumina, phosphorus and LOI. Alongside the standard benchmark 62% Fe delivered China product, more recently-introduced 58% and 65% standards have gained prominence, in a “proliferation of indexes and premiums,” in a movement set to intensify, Martins said.

Changes to IODEX spec

S&P Global Platts changed its IODEX 62% Fe specification in January to reflect market product realities, increasing the typical IODEX alumina and phosphorus content. Further increases in the alumina and phosphorus contents of Australia-origin ores are considered likely, while higher alumina content in Australia-origin medium grade fines has not been matched by increased supply of low alumina ores from Brazil.

Coinciding with the so-called “flight to quality”, major miners stopped bringing on greenfield capacity expansions of “commodity” or standard grade ores. After a protracted period of oversupply, Citi Research’s commodities research strategist Tracy Xian Liao sees seaborne iron ore supplies may start to decline slightly from 2020. However, prices for the more common grades are not expected to gain substantially even amid lower supplies due to “headwinds from greater scrap supplies,” which may also put a cap on coking coal prices, Liao said at a recent London Metal Exchange Focus Day in London.

Ferrous scrap availability is another factor in this year’s structural change: greater scrap arisings as China’s first generation of mass consumer goods reach obsolescence has encouraged the rise of “cleaner” scrap-based electric arc furnaces which do not use coal.

What does decommoditization mean for the market?

1. More investment in iron ore blending: Australia’s Fortescue Metals Group, the world’s fourth biggest iron ore miner, late last year started shipping 60.1% ore blended from a base of its more typical 58% quality ore, to meet demand. This follows Vale’s lead in setting up no fewer than 17 blending stations worldwide. The Brazilian miner is, in effect, “blending all the way into China,” WoodMac’s Griffiths says.

2. More investment in pellet feed production to make pellets, a concentrated high iron content product. Vale sees demand for pellets growing from an estimated 514 million mt worldwide at present to 602 million mt in 2025. Demand for iron ore pellets this year outstripped supply, exacerbated by Brazilian Samarco’s absence from the market since late 2015. This led pellet premiums to inflate and producers including Vale to propose pricing pellet premiums off the 65% Fe  rather than the traditional 62% Fe index. WoodMac reports more than 35 million mt of pellet capacity is proposed to be commissioned within the next 7 years in China, mostly using domestic pellet feed. The closure of Vale’s Corrego do Feijao mine in Brazil following the January 25 tailings dam collapse is seen as adding limited upwards pricing pressure on high-grade iron ore.

3. Different parts of the iron ore market will be subject to different pricing and demand pressures. More indices could emerge, for instance for LOI.

4. Major producers will increasingly serve market niches. According to WoodMac’s Griffiths, Australia’s BHP and Rio Tinto will continue to be consistent suppliers of commodity (lower quality) grades, while facing an increasing need to reduce production costs via use of conveyors and driverless trucks. Vale and other Brazilian producers are favored by having naturally high Fe grades, allowing them to offer more “specialist” products.

5. Despite a wide range of iron ore derivatives already traded on China’s Dalian Commodities Exchange and Singapore Exchange, more financial products may enter this market, especially as players may switch from trade to arbitrage, measuring and trading spreads between iron ore products. SGX launched 65% Fe swaps and futures contracts in early December. However, market players including Neelix’s Martins note that it may become less necessary to hedge higher-value or niche products as these may be less susceptible to price volatility than the broader “commodity” grades.

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In the LOOP: Drop in US crude freight rates entices Asian buyers

US light sweet crudes such as WTI Midland and Bakken have been offered into Asia at lower premiums in recent months amid a drop in freight rates from the US Gulf Coast to the Far East, sources in Asia said Monday.

Taiwan’s CPC was heard to have bought 4 million barrels of WTI Midland crude from an unknown seller for March Loading. The cargo was priced around a $2.25/b premium to Dated Brent on a CIF Taiwan basis. CPC seems to enter the US Gulf Coast market when prices are ideal. The company last bought 4 million barrels of WTI Midland for January loading. But CPC did not seek any WTI spot cargoes for February.

WTI Midland’s differential to WTI cash averaged minus $7.39/b in December, down from minus $5.78/b in November and lower than minus $3.95/b so far in January, according to data from S&P Global Platts.

While most January cargoes have already been sent and few may be sent to Asia in February, March could bring a flurry of US Gulf Coast-to-Asia fixtures as the opportunity reemerges. Upcoming spring refinery maintenance season in the US Gulf Coast region could make more domestic crude barrels available for export, with April differentials for both sweet and sour grades heard to be trading lower.

On Monday, WTI MEH March volumes were assessed at WTI cash plus $5.15/b, with April volumes heard to be traded 25 cents/b lower at plus $4.90/b. Medium sour grade Mars was assessed at WTI cash plus $5.05/b for March volumes, with April volumes heard to be trading 35 cents/b lower. Lower second-month differentials imply weaker demand in April for domestic crude volumes.

US crude continues to make inroads in other countries in Asia. Vietnam’s 148,000 b/d Dung Quat refinery is set to receive its first crude cargo from the US when 1 million barrels of WTI crude will arrive there in April. If testing of that initial cargo is positive, the refinery will likely take more WTI in the future.

Freight rates for VLCCs heading to China out of the US Gulf Coast on a 270,000 mt basis have fallen $400,000 since they reached their January peak at lump sum $7.4 million or $27.41/mt, ($3.54/b) with indications last heard Monday morning in line with the last assessed level of lump sum $7 million or $25.93/mt ($3.34/b).

Overall, freight rates have been weaker over the past month, averaging lump sum $6.94 million or $25.70/mt ($3.32/b) so far in January, compared to $8.26 million or $30.59/mt ($3.95/b) in December 2018. VLCC rates from the US Gulf Coast to Singapore typically follow rates to China, but are typically $1 million cheaper than those to China.

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Investors in energy majors step up demands on climate action

Shareholder activism has a long history in commodities. In the early 17th century, Isaac Le Maire, grain trader and disgruntled former governor of the Dutch East India Company, attempted to break the company’s monopoly by speculatively trading its shares.

His scheme failed, but Le Maire’s desire to shake up the status quo of the trade route between Europe and India eventually led to the discovery of Cape Horn.

Skip forward 400 years and shareholder activism in another Dutch-origin resources giant has taken on a less selfish hue.

In December, the Church of England, along with other investors in Shell, helped to persuade the energy giant to commit to setting targets to cut its carbon footprint by 20% by 2035 and half by 2050. The company’s achievements in reducing carbon emissions is to be linked to executive pay, subject to a shareholder vote in 2020.

The commitment by Shell came in the wake of a startling special report by the Intergovernmental Panel on Climate Change, published in October. The report, commissioned following the 2015 Paris agreement, charts the consequences of a 1.5 degrees Celsius rise in global temperatures from pre-industrial levels.

The Paris agreement commits signatories to taking action to limit temperature rises “well below” 2 C, though many poorer and low-lying coastal countries felt this did not go far enough, and wanted an agreement to limit rises to 1.5 C. Global temperatures have already climbed by around 1 C.

The significant findings of the IPCC special report are that serious environmental changes occur at lower temperatures than previously thought and, while more damaging than a 1 C rise, 1.5 C represents a much more habitable planet than 2 C.

National commitments fall short

One important factor in these changes is the potential feedback loops at certain critical trigger points. For example, the thawing of the northern permafrost, or melting of large sections of polar ice caps. Such events would release large amounts of additional greenhouse gases, or lead to large rises in sea levels. Such events could create feedback loops in the global climate system, locking in further heating of the planet.

So far, so terrifying. But there’s more.

Current commitments by national governments are expected to lead to around 3 C of warming by 2100, with further warming beyond that date. The IEA said in its latest World Energy Outlook that CO2 emissions under planned policies are on a slow upward trend to 2040, and are “far out of step” with what is needed to tackle climate change.

The IPCC says staying within a 1.5 C rise requires “rapid and far-reaching transitions in energy, land, urban and infrastructure (including transport and building), and industrial systems” that are “unprecedented in terms of scale, but not necessarily in terms of speed.”

On the current course, global warming is expected to reach 1.5 C between 2030 and 2052. Limiting temperature rises to 1.5 C requires a 45% reduction in anthropogenic CO2 emissions by 2030 from 2010 levels, and net zero by 2050, according to the IPCC report.

The scale of the challenge highlights the importance of commitments made by the likes of Shell, and the influence shareholders can have in the fight against climate change. National governments – on current commitments – will fall short of their obligations. And with important consumer and producer countries such as the US and Brazil under climate-change-skeptical leadership, the onus falls increasingly on other sections of society.

The motive goes beyond the purely altruistic, though. Agricultural companies’ businesses could be devastated by climate change, with crop yields potentially falling, and harvests failing more often. And energy giants could find themselves owners of billions of dollars of stranded assets, should climate change come to be taken seriously enough to keep fossil fuels in the ground.

Shell case emboldens activists

Following its success with Shell, the Church Commissioners for England, along with the head of New York State’s retirement fund, Thomas DiNapoli, turned their attention to American giant ExxonMobil. Shortly before Christmas, the investor-campaigners filed a shareholder resolution for consideration at the major’s next annual meeting requiring it disclose greenhouse gas reduction targets for the short-, medium- and long-term, in an effort to limit global temperature increases to 1.5 C.

But the campaigners could have their work cut out. ExxonMobil has already attempted to block the Massachusetts Attorney General’s investigation into its research into climate change, although the US Supreme Court rejected the appeal in early January.

As pressure mounts on the energy industry to change, both from governments and from shareholders, we may yet see more companies taking a lead on climate change policy.


This article previously appeared as a column in The National

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New technology boosts Alaska oil resources: Fuel for Thought

Rapid technology advances are allowing explorers and producers in Alaska to add hundreds of millions of barrels of new resources to portfolios at a cost competitive with finding oil the Lower 48 states.

Chief among the technologies being used are advanced 3-D seismic and new data processing techniques, to define and map oil deposits in geological formations that have long been known, but were thought to be unproductive.

<!–more–>Companies are also using advances in horizontal drilling techniques to reach deposits.

In the last two years, over 1.5 billion barrels of recoverable oil has been found mainly in the west central North Slope and northeast National Petroleum Reserve-Alaska, areas companies have explored for years.

New exploration and delineation drilling planned this winter is expected to add to newly discovered resources.

ConocoPhillips has been the most aggressive of the new explorers but independents like Denver-based Armstrong Oil and Gas, in partnership with Repsol, have made major discoveries.

Earlier this year Armstrong sold its 51% share of Pikka, one of its discoveries, to Oil Search, which is now project operator.

Pikka’s resources are estimated at 750 million barrels and Oil Search hopes to expand these to over 1 billion barrels after further drilling.

Willow, a major new discovery by ConocoPhillips, is now estimated to hold 400 to 700 million barrels. The company hopes to expand that but has also found 100 million barrels in a separate find, Narwhal, on state lands to the east.

“We believe we can now compete with shale oil producers in the continental US,” ConocoPhillips Alaska President Joe Marushack said.

“Coiled tubing” drilling

The Nanushuk, a formation covering an area along the Colville River and extending into the northeast NPR-A, is attracting particular interest.

The presence of more oil in these areas has long been known but companies’ confidence they can commercially develop what has been regarded as a marginal resource is now buoyed by rapid advances in horizontal drilling allowing drillers to tap deposits several miles from the surface location of a drill rig.

In “multilateral” wells, as many as five producing legs are drilled off underground from a vertical well to the surface, while in “coiled tubing” drilling, wells can be drilled with flexible tubing at far lower costs than with conventional rotary rigs.

ConocoPhillips has pushed horizontal production wells out to 27,000 feet, over five miles, and when a new specialized rig now being built begins service in 2021, lateral wells out to 40,000 feet, or seven and a half miles, will be possible, ConocoPhillips’ Marushack told a business conference in Anchorage last year.

What this means is that wells drilled horizontally from a single 12-acre gravel pad on the surface will be able to drain oil from 154 square miles of underground reservoir.

Lower capital costs, for barrels of oil developed, has allowed ConocoPhillips to reduce its minimum price threshold for new slope projects from $55 per barrel in 2015 to $42 per barrel now, the company told analysts in presentations last July.

Incremental expansion of existing fields can be done for even less cost, down to $30 per barrel, using technologies like coiled-tubing drilling, the analysts were told.

Some limitations

Independent Hilcorp Energy, another slope producer, is also harnessing a new technology with use of a polymer injection to increase production of thick, viscous oil in the Milne Point field, which is near Prudhoe Bay.

New technologies are also being tweaked. ConocoPhillips, in a new “pentalateral” well (five underground producing legs) in the West Sak viscous oil project has developed methods to access each of the producing legs for work without shutting down the others, company spokesperson Natalie Lowman said.

Some oil service companies have experimented with autonomous drilling units inserted underground to drill on their own, remotely controlled.

Ted Stagg, a retired senior BP drilling engineer in Alaska who helped develop horizontal drilling, said a limitation, for now, to how far wells can be drilled is the cost of recirculating drilling fluid, or “mud”, from the bottom of the hole to the surface.

This is needed to remove rock cuttings and to establish a down-hole pressure with the fluid, to counter any uncontrolled flow of oil or gas – known as a blowout in the industry.

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