Mexico could take multiple paths toward energy self-sufficiency: Fuel for Thought

Mexico President-elect Andres Manuel Lopez Obrador has planned sweeping changes to the country’s energy landscape. Among the key goals of the incoming administration is to make Mexico self-sufficient when it comes to its energy needs, including meeting its rising motor fuel demand.

A capstone to Lopez Obrador’s plan is construction of a new refinery that will end Mexico’s dependency on imports of refined products and cut domestic prices.

However, considering Mexico’s tight public finances and state-owned Pemex’s unsustainable debt levels, there are many
alternatives to building a new refinery the incoming government could evaluate.

The incoming administration said a new refinery in Southern Mexico will be built in three years at a cost of $8.5 billion, but the project’s capacity and how construction will be financed is still unclear. However, Rocio Nahle, the incoming energy secretary, has said the new administration seeks to increase the country’s refining capacity from 1.6 million b/d today to
2.2 million b/d.

Mexico's crude processing volumes on the decline

That cost estimate to build the new refinery could be on the low end based on recent projects.

Last year, Hartree Partners projected that building a 100,000 b/d greenfield refinery in Guyana would cost $5 billion due to the expenses of associated auxiliary services, but the cost of a refinery capable of processing Mexican heavy crude oil would probably be much higher.

It took Northwest Refining six years and $9.7 billion to complete its 79,000 b/d Sturgeon heavy oil refinery in Canada this year.

Any heavy oil refinery would need an expensive cracking capacity to be profitable, considering the expected decrease in the value of fuel oil prices amid changes in marine fuel transportation in the next decade.


One alternative to building a new refinery in Mexico would be to acquire or enhance existing refineries in the country, which has historically been a cheaper venture.

Pemex has been trying to find partners in recent years to raise the resources required to install cracking capacity at its 220,000 b/d Salamanca, 315,000 b/d Tula and 330,000 b/d Salina Cruz refineries. The new government could further encourage those efforts.

Based on Pemex’s data, reconfiguring the three refineries would cost around $9.35 billion and would produce an additional
375,000 b/d of gasoline and diesel and close to 15,000 b/d of jet fuel while eliminating fuel oil production. That kind of output is similar to a 400,000 b/d refinery.

While Lopez Obrador seeks to cut Mexico’s dependency on imported fuel, Pemex branching out to operate a foreign refinery isn’t a bad idea, especially considering US Gulf Coast and Caribbean refineries close by are more efficient than existing facilities in Mexico.

Mexico could look at partnering with the government of Curacao to operate the 330,000b/d Isla Refinery. With the downturn of Venezuela’s PDVSA, that national oil company isn’t in the condition to continue operating Isla Refinery. It is expected PDVSA won’t be able to renew its long-term lease over the facility due to its financial woes.

Leasing Isla Refinery would create significant capex savings for Mexico compared with building a new refinery. Based on news reports, the Curacao government is looking for a 30-year leaseholder that can spend $1.5 billion to overhaul the refinery and supply crude oil for its operation.

If the Mexican government was able to save $7 billion by leasing Isla Refinery, these funds could be used by Pemex to drill nearly 70 ultradeepwater wells like the one it will drill at its Trion project this fall.

For a highly indebted company like Pemex with limited resources, focusing on high-return upstream projects could reap benefits. Pemex CEO Carlos Trevino has told S&P Global Platts it has upstream projects with returns exceeding 100%, while expected returns in its downstream portfolio are 10%-25%.

Another market opportunity for Pemex is Petrobras’ 110,000 b/d Pasadena refinery in Texas. The facility was involved in a
corruption scandal after the Brazilian oil company paid $1.2 billion to acquire the facility compared with the $42.5 million
spent by the previous owner.

The refinery is being sold by Petrobras, attracting interest from several companies. It does require major maintenance work, but acquiring and repairing the facility would be less expensive than building a new greenfield refinery.


Another option Pemex could evaluate is acquiring a stake at another refinery in the US Gulf Coast, as it did at Shell’s 340,000 b/d Deer Park, Texas, refinery in 1993. Shell is the operator of the facility, while Pemex is one of its largest crude oil suppliers.

Pemex could be a valuable partner to any US Gulf Coast refiner, providing a reliable supply of heavy crude oil and ensuring future demand for the facility.

The US Energy Information Administration estimates motor gasoline demand in the US is expected to slide 26% to 6.62 million b/d in 2030 from 9 million b/d in 2016. In contrast, Mexico’s Energy Secretariat (SENER) estimates combined gasoline and diesel demand will grow 50% by 2030 to 1.65 million b/d from 1.1 million b/d in 2017.

US refiners such as Valero, Andeavor and ExxonMobil are keen to make inroads into the Mexican market to shore up the expected decline in demand for gasoline in their own market. It is probable that like in other declining markets, such as Japan, refineries that can’t secure demand amid a decrease in fuel consumption will be shut down, and that makes a partnership with Mexico a profitable possibility.

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Insight: Oil companies scramble to stay ahead of cybersecurity threats

This is the first in a series of two special features on cybersecurity in the oil and gas sector

But for a coding error, an attempted cyberattack last year on a petrochemical plant in Saudi Arabia could have led to a catastrophic explosion.

Malware implanted into the control system to sabotage the plant accidentally triggered a shutdown, but investigators say the attack was one of the most technologically advanced they had ever seen. Chillingly, they say the assailants – still not publicly identified – have likely already fixed the glitch and are lying in wait to target their next facility.

That close call and several others have many experts convinced that the oil industry, even as it invests millions of hours on safety procedures, is ill-prepared on the cyber front.

“The sector is becoming fair game. [Hackers] are seeing opportunities to attack the sector, and facility operators believe they are very well-protected,” a Washington-based cybersecurity analyst at FireEye and former oil industry consultant, Marina Krotofil said, “It is not a good combination.”

Much of the focus on energy-related cybersecurity has been on power plants and grids, but authorities say oil and gas companies — responsible for critical infrastructure including refineries, pipelines and ports — are ripe targets for hackers to implant malware that can disrupt operations, endanger public safety, wreak havoc on markets and disclose sensitive information.

Spending on security measures is insufficient by and large, and collaboration among companies on best practices is woeful, given the secretive and competitive nature of the oil business, according to people in the field.

Often, national security can be at stake.

In the Middle East alone, which accounts for more than a third of global crude production, cyberattacks cost the oil and gas industry $1 billion last year in outages and loss of confidential data, according to a March report by industrial services provider Siemens and the Ponemon Institute. However, only 47% of Middle East oil and gas companies surveyed in the report said they prioritize continually monitoring all infrastructure  for cyber threats and attacks.

“In general, the oil industry is conservative in nature,” said Gary Williams, a senior director for Schneider Electric, which installs control and safety systems in refineries and other critical infrastructure often targeted by hackers. “The industry tends to take an ‘if it ain’t broke, don’t fix it’ approach to how we operate. But we must change this model, and our culture, when it comes to cybersecurity.”

Some experts warn it may take a major successful cyberattack for the industry to fully grasp how great the danger is.

“Organizations need to invest in cybersecurity, but they don’t see it’s a major threat,” senior research fellow with Chatham House’s International Security Department Beyza Unal,  said. “We haven’t seen an event where an entire critical infrastructure got taken out. But it will happen. So how do you get companies to invest in that?”

More complex, more often

Across the industry, energy companies spend less than 0.2% of their revenues on cybersecurity, according to a recent analysis by consultancies Precision Analytics LLC and the CAP Group. That is less than a third of what banks and financial services companies spend protecting their businesses from hackers.

Meanwhile, hackers targeting the industry don’t discriminate by size. Spanish oil company Cepsa is a relative minnow compared with giants like Saudi Aramco or ExxonMobil, but still finds its network targeted about 20 times each day. “Both the range and number of potential attacks are increasing,” Cepsa spokeswoman Marta Llorente Señorans said.

None of the attacks has succeeded, to its knowledge, according to company officials. Its facilities have not failed, and its operations have remained unscathed by any cyber-related outages.

The company, which operates two refineries with a throughput of 430,000 b/d and holds working interests in upstream projects with an output of about 100,000 b/d, is increasing cybersecurity spending by a minimum of 25% annually.

Eni, the Italian energy giant, said it has fended off several cyberattacks targeting its industrial control systems, including at the company’s refineries.

“Cyberattack is one of our corporate top risks,” Eni spokesman Roberto Carlo Albini said. “We have developed a specific security architecture for industrial control systems we perform vulnerability and security assessments on our infrastructure regularly, and we have a dedicated team for security monitoring and incident response.”

Cepsa and Eni’s acknowledgement of the problem is unusual. Many oil and gas companies contacted by S&P Global Platts for this story — ranging from state-owned companies to integrated majors, independent refiners and terminal operators — declined to comment on the issue or disclose cyber defense spending. Few disclosed any assaults on their systems.

Unknown unknowns

But experts say that known attempts account for likely just a fraction of the assaults launched every day – and it’s the ones that remain undetected that are the most worrying.

Many malware programs are intended to gather information on a plant, not necessarily launch an imminent attack, and they may lurk inside a system for months or even years before their creators gain enough intelligence to develop and unleash custom-built viruses that can take down an entire facility.

Hackers who have gained access to a system may just be waiting for the right moment to do their worst, said Daniel Quiggin, a research fellow at Chatham House who specializes in energy systems. “A lot of reconnaissance has gone on,” he said. “To what end, we don’t know, and that is why everybody is so concerned.”

In the case of the Saudi petrochemical plant incident, hackers implanted malware into the facility’s Triconex safety control system — hardware and programs manufactured by Schneider Electric — which regulates voltage, pressure and temperature.

But rather than forcing a shutdown or disruption of the plant, the malware sought to reprogram the safety system, so that fail-safes would not be triggered when a subsequent piece of malware caused the plant to overheat, explode or otherwise catastrophically malfunction, according to FireEye.

Given the sophistication of the malware involved and the likely long development time and cost it would have taken to build, authorities say only one kind of actor could be behind the intrusion: a nation state.

Investigators continue to look into the incident and have neither named the facility nor identified the attackers, though officials suspect they were backed by Saudi Arabia’s longstanding geopolitical rival Iran, a charge Tehran has denied.

With tensions rising in the Middle East, Krotofil said to expect more incidents targeting oil and gas operations there.

“It’s strategic,” she said. “It’s countries where their ability to produce or not produce oil has a huge impact on global oil markets. Therefore, there [are] continuous, multiple attempts to disrupt operations in the Middle East.”

Iran has been steadily building its hacking capabilities, and the fear among US security experts is it could then turn a volley of attacks on the US, as it withdraws from the nuclear deal and re-imposes sanctions that bite at Iran’s oil exports.

“There are legitimate reasons to be concerned that Tehran’s intention in targeting critical infrastructure is to hold social and economic assets in adversarial countries at risk in the event it needs to escalate or retaliate during conflict,” the Carnegie Endowment for Peace warned in a recent report on Iran’s cyber threat.

But Iran, too, has been a cyberattack victim. In 2010, the Stuxnet virus struck Iran’s Natanz uranium enrichment plant, manipulating its computers to send its centrifuges spinning at dangerous speeds. That incident occurred in the lead-up to an Iranian presidential election, and media reports later attributed Stuxnet to the US and Israel.

Late to the game

As the scale and complexity of malware has exploded in recent years, cyberwarfare has emerged as a new front in the battle to gain geopolitical supremacy. Governments and companies are scrambling to stay ahead of hackers and protect vital assets and resources.

But maintaining adequate cyber defenses is costly, as systems must be constantly updated to stay ahead of hackers as they innovate.

The industry has yet to agree on common standards, though trade associations, such as the International Association of Oil & Gas Producers and US refineries group American Fuel and Petrochemical Manufacturers have fostered discussion among their members, in concert with governmental bodies.

However, oversight is uneven and restricted by an inability for national governments and companies to keep pace with the rapid development of malware threats, consultancy Oxford Analytica said in a recent report.

Many governments are already late to the game and hampered by a skills shortage.

“Although leaders might acknowledge the growing importance of the issue, few understand how to proceed,” the report said.

Also troubling is a growing relationship between state actors and criminal groups, with countries providing funding to low-level cybercriminals, as well as access to sophisticated hacking resources via encrypted dark web sites.

“I think what’s interesting that we’ll see in maybe five, 10 years’ time is the nexus between organized crime, terrorist organizations and hackers on the dark web,” Chatham House’s Unal said.

In the past, cyberattacks on oil facilities typically involved cybercriminals seeking proprietary information such as production levels, which they could use for market manipulation, said FireEye’s Krotofil. But attacks in recent years have become far more sinister, ambitious and potentially destructive.

Cyberattacks “have become much, much more complex, much more dramatic,” she said. “Attackers right now are trying to attack everything and see how far they go.”

It is a risk that oil and gas producers can no longer ignore.

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Will Myanmar become a conduit for Iranian crude into China?

On June 1, sometime between the US withdrawal from the JCPOA in early May, and its demand in late June that Asian buyers fully halt Iranian oil purchases, PetroChina snuck in a shipment of Iranian crude through Myanmar to its Yunnan Petrochemical refinery in southern China.

On any other route, this would have been just another Iranian oil shipment. But using the Myanmar-China oil and gas pipeline brings new complications.

That’s because the pipeline has a new avatar — it is now a part of China’s Belt and Road Initiative, along with other large infrastructure projects that were not originally a part of BRI, but were included later to boost the profile of the program.

Sending Iranian crude through an oil pipeline with the “Belt and Road” label removes any doubts of whether BRI’s projects have political motives or not.

For critics of BRI, it adds fodder to the narrative that the infrastructure plan is a tool for China to undercut the influence of the US. BRI already has a serious public relations problem and is viewed with suspicion, sometimes for good reason.

Earlier this week, the renewal of US secondary sanctions on Iran faced strong opposition from the remaining JCPOA signatories. China has made it clear it will continue to import Iranian barrels, and using a BRI project to do so will give the US ammunition to criticize BRI openly, potentially leaving the host country open to US reprisals.

BRI has not been particularly polarizing so far, and its participants have included US allies. Oil and gas pipelines are magnets for controversy, however. From the Sumed pipeline in the Middle East to Nordstream 2 in Europe, there hasn’t been an international oil or gas pipeline that was devoid of geopolitics. Myanmar will be no different.


The Panama-flagged Dore delivered its cargo of Iranian crudes at Maday Island on June 1, the only vessel to have shipped oil from Iran to Myanmar since the 13 million mt/year (260,000 b/d) Yunnan Petrochemical refinery in southern China started operations in August last year.

Dore’s cargo of 948,000 barrels of crude oil included 474,000 barrels of Iranian South Pars condensate. The refinery said it also processed 56,000 mt of Iranian Heavy crude received via the 1,420 km pipeline, Platts reported previously.

This was the first batch of Iranian Heavy crude processed by a PetroChina refinery, and is unlikely to be the last. Iranian grades contain a relatively higher amount of metallic and chloride contaminants that corrodes refinery units, due to which some of PetroChina’s biggest refineries like Dalian Petrochemical and Guangxi Petrochemical, were unable to crack the crude.

Yunnan Petrochemical has a 1.2 million mt/year delayed coking unit that enables it to process Iranian crude, and it has already tested the first cargo successfully. Other major Chinese refineries under Sinopec have used Iranian crudes and found them attractive because of a high naphtha yield, which is needed for petrochemical products.

All of this paves the way for the China-Myanmar pipeline to become a conduit for Iranian crude, even if it is for just one refinery, which if fully utilized will account for nearly a third of China’s intake of Iranian crude. China’s imports of Iranian crude were around 638,000 b/d in the first half this year.

The Myanmar-China pipeline runs from Maday Island, near the town of Kyaukpyu in Rakhine state, and connects with China’s domestic pipeline to Kunming city in Yunnan province. It is fed by a deepwater VLCC terminal and tank storage farm, and was negotiated with the former military government of Myanmar. State-owned Chinese media now call it a “pioneer project” of BRI.

The final question is around the implications for Myanmar, and the legal complications for players in the Iran crude supply chain, like pipeline operators, shipowners, ports or banks involved.

Legal experts advise caution.

“In respect of persons involved in transporting or storing petroleum from Iran, there is a risk that they could be subject to US sanctions,” Clyde & Co Partner Avryl Lattin said.

Sanctions or other punitive measures of the Trump administration are often considered on a case-by-case basis, such as special waivers given to India to import Russian military equipment because of its position as a budding strategic partner of Washington’s Indo-Pacific strategy, Collin Koh, Research Fellow at the Maritime Security Programme of the Institute of Defence and Strategic Studies, Singapore, said.

“It depends a lot on how the target country weighs in significance within the US strategic calculus. Myanmar is certainly not one country that the US can afford to alienate now,” Koh said.

There are signs that Myanmar wants to turn towards China due to the Rakhine issue, but at the same time Naypyidaw is more amenable to Western concerns and interests than ever before, He said. Due to this, even India and Australia are careful in their treatment of Myanmar.

So the US may not want to exacerbate the situation by imposing punitive actions on Myanmar just because Iranian oil was piped through its territory to southern China, Koh added.

“The concerns are long-term geopolitics,” he said.

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EU forges ahead with steel sector M&A – but it won’t solve overcapacity

European steel’s current major M&A activity — driven by market recovery since mid-2017 — aims to achieve synergies and boost cost-effectiveness in a global steel sector still plagued by as much as 657 million mt of overcapacity, according to Organization for Economic Cooperation and Development estimates.

ArcelorMittal (AM), the world’s biggest steelmaker, is to acquire Italy’s biggest, Ilva, while the knot has been tied between Thyssenkrupp Steel Europe and Tata Steel Europe in a union still to receive the European Commission’s final blessing. But while both deals are expected to proceed, they won’t solve Europe’s steel overcapacity problem: analysts maintain actual capacity closures are still far off due to restrictions by local authorities and trade unions.

Big is not always beautiful, and especially not where the EC is concerned: the M&A merry-go-round of shifting assets will continue in a move to preserve jobs and improve loss-making installations. Social concerns play a pivotal role in the EC’s holistic industrial restructuring scheme. The TK-Tata merger may require tinplate assets to be sold. AM’s merger with Ilva will also require divestments: German steelmaker Salzgitter mid-July submitted an offer to buy production lines at AM mills in Dudelange, Luxembourg and Liege, Belgium.

Analysts estimate the EU steel industry’s overcapacity in 2016 was more than 5 million mt/year, around 3% of regional domestic steel consumption of 157 million mt at the time: a small amount compared to the global figure and which followed major capacity cuts in the EU from 2014-2016, when 13.5 million mt was permanently taken out of production, according to OECD data.

However, even 5 million mt of inefficient or unproductive capacity may be costly to maintain when cost-effective production is the best tool to help correct the EU’s steel trade deficit with the rest of the world: this deficit broadened to 7.9 million mt in the first five months of 2018, on an annualized basis nearly doubling from the previous year.

Recent M&A activity will “fail to reduce overcapacity issues as a result of takeover terms…smaller steelmakers will likely look to acquire rivals if the bigger deals go through in an effort to scale up their operations to better compete with these two larger groups. We also see the scope for niche M&A deals in specialty steel,” said Moody’s vice president, senior credit officer Gianmarco Migliavacca.

Cases in point: Schmolz +Bickenbach recently acquired Asco Industries (Ascometal) to strengthen its position in Europe’s special engineering long steel segment, while Aperam is buying VDM Metals Holding GmbH to bolster its position in special alloys. Cross-border deals are playing a part: Japan’s biggest steelmaker, Nippon Steel & Sumitomo Metal Corp., acquired Swedish engineering steelmaker Ovako Group AB in June.

From a purely commercial point of view, the odds are stacked against complete M&A success in the mature, high-cost European steel market while modern steel mills emerge elsewhere, particularly in Asia. The TK-Tata Steel Europe deal is seen very much in the hands of the unions, with promises of no compulsory redundancies until 2026 preventing any major cost savings in labor.

Charles de Lusignan, spokesman for Eurofer, the European Steel Association, said: “Consolidation in the sector does not a priori result in reductions in capacity, but it certainly does not preclude it either: it really rather depends on the circumstance-specific investment decisions of a given new company.”

The backdrop is improving for European steel’s profitability overall: the EC has over the past two years taken a more proactive stance on dumping of steel, and has stood up to the US Section 232 import tariffs with a carefully thought out tariffs and quota import control system. China has substantially reduced its steel exports and global steel prices have remained firm as protectionism has risen. According to Eurofer, production activity in EU steel-using sectors was forecast to grow by 2.8% in 2018 and by 1.9% in 2019, above expected GDP EU growth.

Still, this is perhaps a moment for Europe’s mills to reinforce their emphasis on quality rather than quantity, especially as stricter production regulations loom in the region’s carbon markets.

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Insight: Market watchers fret about future of US wholesale power markets

US power markets are in the spotlight amid a flurry of power plant retirements and subsequent efforts by various forces to keep them afloat. Some market watchers suggest the shifts in market structure, resource mixes and policy sets should come as no surprise – and that perhaps the country’s experiment with competitive wholesale markets should be abandoned – while others believe that power markets will persevere and even expand.

US power markets were restructured in the 1990s to introduce more market-based competition and separate monopolies many utilities had on the value chain, from generation to transmission and local delivery.

But in recent years, the merchant power generation model, in which generators earn profits by selling energy and capacity in wholesale markets, has come under threat – with coal and nuclear particularly hard hit.

US power generation mix

Squeezed by abundant shale gas and the growth of renewables, coal plants have been shutting at a rapid clip, with 46.5 GW having retired between 2013 and 2018. That total does not include permanent conversions to natural gas, which might account for about an additional 10 GW, according to S&P Global Platts Analytics.

In addition, 4.8 GW of nuclear capacity has retired over the same timeframe. On a net basis, nuclear plant owners have announced 10.8 GW of retirements by 2023.

While many of these plants are older and less efficient than newer technologies, coal and nuclear power plants have also struggled to make money in competitive markets, where cheap natural gas prices have put downward pressure on power prices.

In order to stem the tide of recent coal and nuclear plant retirements, the US Department of Energy issued a Notice of Proposed Rulemaking last September, calling for cost recovery for power plants that maintain 90 days of fuel onsite. The DOE had argued that select nuclear and coal-fired facilities needed financial support to remain operational and support power grid resilience.

In January, however, the Federal Energy Regulatory Commission rejected the NOPR, saying that US power markets were not facing a supply risk. But FERC did agree to study the resilience of the US power system, a process that remains ongoing.

In June, US President Donald Trump directed Energy Secretary Rick Perry to take emergency steps to help financially struggling coal and nuclear power plants. Perry has confirmed DOE is considering whether two obscure laws could be used to that effect, but has given no timeline for acting.

Perry told reporters in late June that power market economics are “secondary from my perspective,” when considering grid reliability through a national security lens.

Markets ‘on life support’

“I would go so far as to say that the pure restructured model is, at best, on life support in many of the states where it was adopted,” said former FERC commissioner Tony Clark in a recent editorial. “The federal wholesale regulators at FERC designed an entire construct around the restructured market model, but places like New York, New Jersey, Massachusetts and Illinois can no longer credibly be called full retail choice/restructured states,” he said.

Clark’s colleagues at law firm Wilkinson, Barker & Knauer wrote in a recent white paper that the only functioning regulatory constructs for electricity were vertically integrated markets with planned utilities underneath residual energy markets, like the Southwest Power Pool and Midcontinent System Operator. The deregulated model “lays in tatters, trampled by interventions,” they said.

In addition to shifting economic winds fanned by the shale gas revolution and decreasing costs for renewable energy sources, restructured power markets are being challenged by state clean energy mandates, public policies and subsidies.

“I think they’re [power markets] in real danger of unraveling,” David Ismay, senior staff attorney with the Conservation Law Foundation, said during a panel discussion in May at the S&P Global Platts Northeast Power and Gas Conference in New York.

In the name of addressing climate change and local air pollution, states – particularly in the northeast – have been enacting policies like renewable portfolio standards and, more recently, zero-emissions credit programs to save nuclear power plants that don’t release carbon or other smokestack pollutants.

Often described as “out-of-market” subsidies, such policies irritate competitive power markets by favoring certain generation sources. Market purists say these policies have no place in the wholesale markets and regional grid operators have been creating rules to protect market integrity from policy distortion.

This is not without controversy, however, and has led to friction between grid operators, merchant generators and states in New England, New York and the PJM Interconnection. Nuclear plant subsidies and potential action from the DOE to save selected coal and nuclear plants “threaten the foundations of the PJM capacity market and the PJM energy market as well as the competitiveness of PJM markets overall,” the grid operator’s independent market monitor, Monitoring Analytics, said in a recent report.

Carbon price needed

Multiple experts pointed to the lack of a carbon price as a strong contributor to competitive power market stress. “The primary issue remains the failure to implement means of pricing carbon, and the corresponding failure of state governments to rely on such mechanisms in lieu of technology-specific targeted incentives,” said AJ Goulding, faculty affiliate of Columbia University’s Center for Global Energy Policy and president of London Economics International.

“More broadly, the issue that competitive electricity markets need to grapple with is how to economically dispatch a growing mix of zero marginal cost resources and storage as these resources increase their share of the overall installed capacity base,” he said.

Due to the absence of a coherent carbon pricing policy, states have been using second- and third-best methods to direct investments, said William Hogan, the Raymond Plank Professor of Global Energy Policy at Harvard University’s John F. Kennedy School of Government. “As always, the confused situation sets the stage for special interest pleading for government to subsidize or mandate investments that would otherwise be uneconomic but have powerful supporters,” he said.

Scott Miller, executive director of the Western Power Trading Forum, said there was a “push me, pull you” effect with regard to states pushing renewable portfolio standards, federal policies of tax credits and other subsidies that are now producing inexpensive renewables that knock traditional thermal baseload generation out of the dispatch.

“Markets will survive because they make the most sense over time as macroeconomic effects that are unknown now eventually cause a return to rationality and market economics,” Miller said. “However a lot depends on what FERC does in the short-term,” he added.

Renewables optimism

Beyond the current challenges, there is some optimism about the potential for wholesale power markets to ensure a more efficient allocation of energy resources in future. If small-scale distributed generation and renewables became more widespread, Harvard University’s Hogan said that markets and price signals would likely play a key role. “If the future implies expansion of distributed energy resources that are going to facilitate operations, then it is hard to conceive of success here without a market and improved pricing signals,” he said.

“Hence, from the perspective of short-term wholesale markets, the experiment has not run its course. If anything, we are on the cusp of a great expansion of the importance of markets in the future electricity system,” Hogan said. The short-term markets needed improved pricing, most notably in terms of treating scarcity conditions and providing the right signal at the right time, he added.

Power markets are clearly at an inflection point where they could devolve into more regulated structures, or new hybrid models. The next few months will be critical, as some market participants pursue their agendas and others brace for the impact of potential federal intervention.

“The future of competitive wholesale markets is not preordained but will play out case by case, issue by issue, market by market,” John Shelk, president and CEO of trade group Electric Power Supply Association, told S&P Global Platts. “That future will hinge on whether the DOE succeeds in bailing out coal and nuclear, whether states take markets for granted with out-of-market subsidy schemes, whether courts allow states to intrude on FERC’s regulatory space, whether FERC acts boldly to mitigate federal and state out-of-market payments, and ultimately whether consumers and others band together to defend the markets. If markets fall, consumers lose,” he said.

Whatever the outcome, US power markets appear set for considerable change over the coming months and years.

Additional reporting by Mark Watson

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Don’t hold your breath — 2+42 Chinese steel-producing cities

On July 20, Tangshan, the steelmaking hub in northern China’s Hebei province, turned up the heat on pollutant industries by imposing a 43-day output cut on local blast furnaces. In parallel, Chinese authorities are removing a further 30 million mt/year of crude steel capacity.

When compared with the winter heating season of November 2017 to March 2018, the iteration proposed for 2018 is set to affect a greater land-area.

China imposed production cuts on blast furnaces and sinter plants across “2+26” steel-producing cities in 2017. A total of 51.8 million mt/year of pig iron capacity was reduced during that period, according to S&P Global Platts calculations.

This year’s program is expected to effect “2+42” cities.

Estimates steel mill capacity cuts during the 2017/18 winter heating season

2018/2019 winter cut: what to expect

While China has not officially announced details of the 2018-2019 winter heating season cuts, the state council released its “three-year blue skies” plan on July 3. Under this decree, areas for winter air pollution controls will be expanded from Beijing-Tianjin-Hebei to the Fen-Wei plain and the Yangtze River delta.

Platts calculates that an extra 40 million mt/year of pig iron capacity would be subject to the 120 days winter output cuts in 2018-2019, assuming the same utilization rate of 50%-70% as experienced last winter.

It is also widely expected that the production curbs this coming winter will likely be differentiated based on the emission level at each steel mill. Managers at large state-owned steel mill in Tangshan said they expected differentiated measures mill-by-mill because this will give companies more incentive to improve their emissions levels.

“The government has set up the 2018 decapacity target (of 30 million mt/year) and this applies to the winter heating season. Therefore, the remainder of the task for each mill will be different. I think the government will execute the strategy with more flexibility this time,” they said.

The Fen-Wei plain, and the Jiangsu and Anhui provinces are “highly likely to be included into the list this time as well,” a purchasing manager at a large private steel mill in the Hebei province commented. “The curbs on blast furnace output in the Tangshan region could be matched to that of sintering, in a range of 30%-50% across all steel mills in the region.”

Blue sky and the rise of scrap

The cuts imposed during the 2017/2018 winter heating season illustrated that achieving fresher air does not necessarily result in lower crude steel output.

Instead, the national data shows an increase to 344 million mt of crude steel produced during the 2017-2018 winter period, 3% higher than the same year-earlier period, when no restrictions were imposed.

Furthermore, January-June output of 449 million mt is 7% higher than H1 2017, and also the highest year-to-date output on record. S&P Global Market Intelligence expects China to produce a new record of approximately 873 million mt of crude steel in 2018.

Higher-than-expected steel output has been driven largely by robust domestic demand and by the resultant strong steel mill margins. Mill profitability over the winter period averaged $140/mt for rebar and $130/mt for hot-rolled coil, according to Platts data. Steelmakers responded to the strong economic incentive by lifting the ratio of scrap usage, which was in abundance in China due to the closure of induction furnace production. National Bureau of Statistics data shows that pig iron output in H1 2018 was little changed at 370 million mt, up 2% year on year. This compares with stronger growth of 7% in crude steel production.

Platts China domestic steel mill margins

What do these cuts mean for seaborne prices?

Market Intelligence expects 62% Fe seaborne prices of iron ore to experience some seasonal uplift in Q3 2018, and for prices to average $69.0/mt CFR China in 2018. These winter suspensions to Chinese steelmaking facilities will increase the amplitude and duration of volatility in seaborne prices as market participants struggle to clarify the impact on demand.

Over-capacity remains a global issue although the shuttering of pollutant Chinese capacity and elevated utilisation rates of existing steel capacity in China will improve the situation. We expect world utilization rates to improve from a recent low of 67.8% in 2016 to 70.5% in 2018.

Market Intelligence expect 62% Fe prices to average $65.7/mt in Q4 2018, albeit with prominent volatility and with continued environmental pressures to enact stronger downward forces on 58% iron prices.

Premiums on direct charge material are expected to remain at elevated levels. The 58% to 62% iron differential has remained broadly constant since Q4 2017 at approximately $28.8/mt on October 17.

China steel prices

This article is a collaborative analysis by S&P Global Platts’ Jeffery Lu and S&P Global Market Intelligence’s Max Court. Both companies are owned by S&P Global Inc.

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Insight from Washington: US abandons oil sanctions to avoid owning Venezuela’s collapse

Just more than a year ago, it was not a question of ‘if’, but ‘when.’

As Venezuela’s leftist leader Nicolas Maduro consolidated power in an election derided as a fraud by the international community, the Trump administration readied exacting sanctions on the South American nation’s oil sector.

“All options are on the table,” said a senior administration official during a July 2017 briefing with reporters, adding that sanctions could be imposed in a matter of days. “All options are being discussed and debated.”

Analysts widely expected sanctions on diluent the US was exporting to Venezuelan refineries first, followed by a prohibition, perhaps phased in over a matter of months, on imports of Venezuelan crude into the US. It was unclear if US refiners, who had long imported Venezuelan crude, would be allowed to continue under an interim “grandfathered” arrangement, but analysts mostly agreed that sanctions were coming.

At the time, the US was importing about 800,000 b/d of Venezuelan crude and the administration was mostly concerned about the impact an import embargo would have on US Gulf Coast refineries, which would need to look for new sources of heavy crude.

Oil sector sanctions from the US seemed so likely that then-US Secretary of State Rex Tillerson told reporters that the administration was looking at ways to soften the impact of the sanctions once they were imposed.

“We’re going to undertake a very quick study to see: Are there some things that the US could easily do with our rich energy endowment, with the infrastructure that we already have available – what could we do to perhaps soften any impact of that?” Tillerson, the former CEO of ExxonMobil, said.

A year later, the US is importing less crude from Venezuela (about 530,300 b/d in July, according to preliminary US Customs data), but Gulf Coast refiners, particularly Valero, continue to rely on these imports.

In fact, US refiners may be importing even more, if Venezuela’s oil sector was not seemingly in a death spiral. Roughly one if every five barrels of oil imported by US Gulf Coast refiners comes from Venezuela.

The EIA forecasts Venezuelan oil production to fall below 1 million b/d by the end of this year, down from 2.3 million b/d in January 2016 as joint ventures fall apart and PDVSA, the state-owned oil company, struggles to feed, let alone pay, its workers. PDVSA has notified international customers than it cannot fully meet crude supply commitments and the country’s active rig count has fallen below 30, according to Baker Hughes International Rig Counts.

By the end of 2019, Venezuelan crude oil output is expected to plummet to 700,000 b/d, making it likely that it will produce less than the US state of New Mexico.

“We’ve never seen an industry or a country collapse this fast and this hard,” said EIA analyst Lejla Villar in a recent interview with the S&P Global Platts Capitol Crude podcast. “We’ve never seen anything like this.”

Industry collapse

The downfall of Venezuela’s chief industry, coupled with International Monetary Fund predictions that inflation in the country will skyrocket to 1 million percent by the end of this year, have created an unusual scenario, in which Maduro may even welcome US sanctions on its oil sector. As Venezuela’s economy continues to unravel, leading to surging prices and rampant hunger, Maduro could try to pin the blame on sanctions.

“If you break it, you buy it,” said George David Banks, a former international energy and environment adviser to President Trump. “The White House doesn’t want to own this crisis.”

The US has sanctioned individuals in Venezuela, including Maduro; prohibited the purchase and sale of any Venezuelan government debt, including any bonds issued by PDVSA; and banned the use of the Venezuela-issued digital currency known as the petro. But oil sector sanctions are viewed as the most powerful penalty remaining and one the Trump administration is more hesitant than ever to use.

“There’s already a humanitarian crisis, but we don’t own that, the Maduro government owns that,” Banks said. “We don’t want to lose the people of Venezuela and you don’t want to pursue a policy that jeopardizes that.”

David Goldwyn, president of Goldwyn Global Strategies and a former special envoy and coordinator for international energy affairs at the US State Department, speculated that it would take extreme action, such as a military assault on a civilian rebellion, for the US to now impose oil sector sanctions. “The system is collapsing and this administration does not want to own the collapse,” Goldwyn said.

The path ahead for Venezuela’s oil sector has, likely, never been less certain. And it remains to be seen what a full collapse of an economy looks like. It is clear, however, that the US wants to avoid blame for accelerating that collapse and has abandoned, at least for now, consideration of oil sanctions.

When Venezuela’s oil sector hits rock bottom, the US does not want to be accused of dragging it there.

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LOOP Sour crude becomes heavier, sweeter in July

LOOP Sour crude became heavier and sweeter in July, with an average API gravity of 29.6 degrees and typical sulfur content of 2.5%.

Additionally, more than 500,000 barrels of LOOP Sour was delivered from storage in July, according to data from the Louisiana Offshore Oil Port.

LOOP Sour is comprised of the US Gulf of Mexico medium sour grades Mars and Poseidon and a crude blend called Segregation 17, into which the Middle Eastern grades Arab Medium, Basrah Light and Kuwait Export Crude can be delivered.

About 8.7 million barrels of Basrah Light were imported to Morgan City, Louisiana, in July. This represents a month-on-month increase of 5.2 million barrels compared with June. Other crudes imported into LOOP during July included heavy Merey and light sweet Santa Barbara from Venezuela and Maya crude from Mexico.

In related news, LOOP and Matrix Markets will host Tuesday their monthly storage futures auction for LOOP Sour capacity allocation contracts, Matrix announced last week.

The companies will auction 8,500 CACs worth the equivalent of 8.5 million barrels of storage. The front-month of September will see 1,200 CACs put up for sale while the most for any contract will be in Q1 2019, where 3,300 CACs will be auctioned. This month’s auction total is a decrease from July?s 11,900 CACs that were offered. July’s auction represented the most CACs offered since April 2015, while the August auction is a return to the yearly average amount.

The value of those CACs has traded between 5-8 cents/b since December 2017, when the minimum bid price LOOP will accept was lowered to 5 cents/b.

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Energy security is a two-way street: Fuel for Thought

US Energy Secretary Rick Perry’s recent claim that energy independence is within reach overlooks a fundamental principle of interconnected global trade: Producing countries need security of demand as much as consuming countries need security of supply.

While the US Energy Information Administration projects the US will become a net energy exporter within the next few years, as it already is for natural gas, the country will still need to buy heavier and sourer crude to blend with its lighter sweet grades and will be reliant on the political and economic relations it fosters with other energy suppliers.

Dependence can be as much a strength as a weakness, helping to guarantee security of supply and security of demand for both parties.

“History tells us that energy independence does not necessarily equate with energy security; Winston Churchill’s wise advice on achieving energy security through ‘variety and variety alone’ is as valid today as it was a Century ago,” said Carole Nakhle, CEO of consultancy Crystol Energy.

Nakhle points to the Persian Gulf countries’ growing relationship with Asia, not only through bilateral oil trade but through direct energy investment as an example of the interdependency of long-term supplies.

“However, competitive market structures give consumers stronger bargaining power simply because they have more choice,” she added.


With gas supply, the debate has centered around Russia and its hegemonic supply of gas through pipelines across Europe. With oil, it has focused around the US and Iran and key oil and shipping routes in the Middle East.

On the gas side, Gazprom tried to assuage the EU’s fears earlier this year by suggesting the rising Russian share of the European gas market should not be a concern as customers are merely choosing the cheapest option for their gas needs.

That hasn’t stopped the jitters. Especially with plans afoot to build Nord Stream 2 across the Baltic Sea along a similar route to its 55 Bcm/year Nord Stream pipeline that will allow Russia to send up to 110 Bcm/year to Europe through the Baltic Sea route.

Neither the threat of US sanctions nor legal efforts by the European Commission have succeeded so far in derailing the project.

While it is true that Gazprom’s share of the European gas market has risen from about 25% earlier in the decade to around 34% in 2017, it is also true that Europe has a diversified supply.

EU security rules have promoted more two-way gas links in Central and Eastern Europe, allowing more gas to flow from other directions if there is a problem with supplies.


LNG import terminals provide access to new gas sources, including the US, with more potential infrastructure being planned, though at present, three-quarters of Europe’s existing LNG import capacity lies idle with economics being the arbiter of the EU’s gas imports, not politics.

Then there is the Southern Gas Corridor, with a network of ventures designed to bring gas from the Caspian region to Europe.

Three gas pipeline projects will provide a continuous route through Azerbaijan, Georgia, Turkey, Greece, Albania and Italy and is expected to provide 10 Bcm a year of gas to Europe starting in 2020.

Russia has never directly cut off gas to Europe.

In 2009, a dispute between Ukraine and Russia led to gas supplies to Europe being disrupted for 13 days and it is this fragile relation which is the biggest risk for the EU.

Even then, the standoff between Russian and its neighbor came down to money.


Despite the relative tightening of global oil supplies after OPEC and its allies slashed output to rebalance the market, fears of a supply shock at this stage are overhyped.

While Venezuela, Libya and Iran remain output risks, there appears plenty of oil in the strategic stocks in the big consuming nations US and China, while the IEA – a body set up to promote energy security and respond to disruptions – has released oil stocks three times in its 40-year history to handle emergencies.

Attack risk to key oil choke points, Bab al-Mandab

Indeed, the concerns appear over two critical sea routes. The Strait of Hormuz sees 18.5 million b/d of crude pass through its Persian Gulf choke point and Bab al-Mandab sees 5 million b/d of crude travel through its “gate of tears” on the Red Sea.

Iran has threatened the supply of oil from fellow OPEC members should it lose market share as US sanctions from November 4 take their toll.

Analysts believe 1 million b/d could come off the market by the end of the year which could be replaced by Saudi Arabian, Russian and Gulf barrels. The US Navy stands by to protect key waterways and analysts doubt that any blockade could last for long.

Houthi rebels, meanwhile, have upped their attacks on key Saudi infrastructure, which saw the temporary closure of the Bab al-Mandab even if that only raised eyebrows rather than hackles.

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US utility coal stockpiles continue to decline; markets not alarmed

Utility coal stockpiles stood at 128.4 million st at the end of May, according to the most recent US Energy Information Administration data, released last week.

The figure was down 20.9% from the year-ago month, and down 23.7% from the five-year average for the month.

Stockpiles typically build during May, as utilities prepare for summer burn. The five-year average is a build of 3.1 million st; this year, it was a drawdown of 540,000 st.

According to Arlington, Virginia-based energy consultancy Energy Ventures Analysis, utility stockpiles at the end of June stood at 119.2 million st. The EVA total, based on survey responses and modeling, would be 24.4% off the EIA’s year-ago figure for June, and 26.5% below from the five-year average.

It would also be the lowest stockpile figure March 2014, which followed the so-called Polar Vortex of early 2014.

US electric power sector coal stockpiles

Yet coal prices have shown little reaction. The over-the-counter price for front-month Powder River Basin 8,800 Btu/lb coal was assessed Friday at $12.25/st, the lowest price this year. The price started the year at $12.40/st, peaked at $13/st February 23, then has largely declined in the following weeks.

In the East, the front-month price for Central Appalachia rail (CSX) coal, basis 12,500 Btu/lb, was assessed Friday at $64.75/st, nearly matching its year-to-date high of $65.05/st in early January, but market watchers peg the current rally to overseas prices rather than domestic demand.

“You don’t see people rushing out to buy coal,” said Seth Schwartz, EVA’s president.

Low burn

Part of the reason is due to low burn. Cheap natural gas and increasing wind generation have pushed down coal capacity factors, so days of burn — the amount of time to expend stockpiles at the current rate of consumption — remain relatively high.

According to EIA data released earlier this week, days of burn at bituminous coal plants as of May 31 stood at 75 days, up 2.5% from the five-year average for the month, while days of burn at subbituminous coal plants stood at 78 days, up 14%.

EVA reported days of burn for all plants at the end of June stood at 68 days.

Given utilities typically target a stockpile of roughly 50-60 days, inventories have yet to be a point of concern.

“We haven’t seen any issues yet, and I don’t really anticipate any issues given where we project stockpiles are going,” said Joe Aldina with S&P Global Platts Analytics.

Platts Analytics forecasts national days of burn to end July at 59 days, and average 65 days between August and January 2019.

‘Stockpile managers’

Other reasons stockpiles continue to decline is uncertain demand, as well as a reluctance to become “stockpile managers.”

“It costs a lot of money to keep coal on the ground, and it’s happened three times in the last decade,” said Schwartz, pointing to the recession (2008-2009), the year without a winter (2012) and the mild winter/historic low natural gas prices in 2016.

“Utilities generally have pulled back in terms of how much they are committing under contract, because they’ve found burn is not as predictable as it used to be,” said Schwartz. “When running as baseload you know what you were go to burn three years out, but now you’ve had several events where you’ve been over-contracted, and that’s not something anyone wants to do.”

Using EIA data going back to 2004, utility stockpiles bottomed at 97.5 million st in January 2005. Should stockpiles drop below those levels, “people would start to scream,” said Schwartz.

As August nears, the domestic coal market is hardly screaming, save for higher gas.

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