Friday, March 31, 2023

Lundin Mining pays $950m for controlling stake in Caserones copper mine in Chile

Lundin Mining buys controlling stake in Caserones copper mine in Chile

Caserones copper mine is located in Chile’s arid north, close to the border with Argentina. (Image courtesy of Minera Lumina Copper Chile.) 

Canada’s Lundin Mining (TSX: LUN)) is buying a majority stake in the Caserones copper-molybdenum mine in Chile for about $950 million, adding to a flow of deals as miners seek to increase their exposure to the metal crucial for the world’s energy transition.

The miner will acquire a 51% stake in the company that operates Caserones from its owner Japan’s JX Nippon Mining & Metals Corp.

Lundin said it will pay $800 million in cash upfront, plus $150 million over six years from the deal’s completion.

The transaction also gives the Toronto-based miner the right to purchase an additional interest of up to 19% in the copper-molybdenum mine for $350 million over five years.

“The initial controlling interest increases our exposure to what we believe is a growing top-tier copper mining district. We retain the option to further increase our ownership over the next few years at an attractive price,” Lundin’s chief executive, Peter Rockandel, said in the statement.

JX Nippon Mining & Metals said the decision to sell part of Lumina Copper, its subsidiary and operator of Caserones, was part of an asset portfolio review. 

The firm became the majority owner of the Chilean mine in November 2020, when it acquired the stakes from its partners in the operation Mitsui & Co and Mitsui Mining and Smelting.

The operation has suffered a series of ramp-up delays and cost overruns since it began producing in May 2014. Its annual production of roughly 100,000 tonnes still falls short of the 150,000 tonnes a year intended when construction of the mine began.

Completion of the deal is expected by June 2023, Lundin said.

Caserones is located at an altitude of 4,200m to 4,600m above sea level in Chile’s Atacama desert, close to the Argentina border.

Lundin Mining grabbed headlines last year when a sinkhole opened up near one of the company’s mines in Chile — Alcaparrosa.

CHART: Demand is soaring, but global mining is not expanding

Mining companies operating in Russia improve in environmental transparency rating - WWF

Capex freeze. Dvoinoye mine in Khabarovsk Krai, 2019. (Image: Kinross Gold) 

A new report by BMO Capital Markets has a trenchant chart showing just to what extent mining companies – flush with cash – are opting to return money to shareholders rather than build new mines. 

Global mining’s enthusiasm for brown and greenfield projects has fizzled over the last decade despite near universal agreement that in the coming decades demand for metals and minerals will boom due to the green energy transition.

BMO says while companies “have started to talk more openly about investment,” so far they are “doing little about it”.

Over the past 20 years, expansion capital spending across the industry has typically run above 20% of EBITDA, which is to be expected in an industry with depleting assets and falling grades (click here for a copper ore grade graph). 

The authors of the report point out that the past couple of years have seen this metric slip to around 10%, “with shareholder returns favoured even as free cash rose.”

“Given the timeline to bring a mine to market, this lack of investment is storing up issues for later in the decade, where balances look incrementally tighter.” 

Buying not building 

“Moreover, given it has never been harder to build a new mine owing to capex escalation concerns, shareholder resistance and environmental/ESG challenges, we see companies looking towards buying rather than building any growth,” says BMO. 

Given this, the investment bank sees the need for medium-to long-term pricing to trade at a premium to the cost curve “given the need to substitute or thrift demand in a number of metals, particularly those exposed to the fuel to materials transition.” 

Also in the report, where BMO has upped its price forecast for most of the commodities it covers (notably molybdenum +59%, gold +13%, and copper and zinc both +10%), is a section on changes to China’s raw materials model.

If mining companies in the West are planning to buy their way out of years of underinvestment in new assets, they will have stiff competition, not just at home:

“Ensuring availability of raw material supply is not a new policy for China, but it has clearly been moved up the agenda since last year’s NPC. 

“We view this as effectively a carte blanche to Chinese SOEs to invest in mines overseas again, both mining companies and, potentially, battery and automakers such as CATL and BYD.”

Glenn Beck & Tucker Carlson REACT to Trump's INDICTMENT

Brazil, China strike trade deal agreement to ditch US dollar 

Brazil and China have reportedly struck a deal to ditch the U.S. dollar in favor of their own currencies in trade transactions. 

The deal, announced Wednesday, will enable China and Brazil to carry out trade and financial transactions directly, exchanging yuan for reais – or vice versa – rather than first converting their currencies to the U.S. dollar.  


President of the Brazilian Export and Investment Promotion Agency (ApexBrasil) Jorge Viana speaks at the Brazil-China Business Seminar in Beijing, China, on March 29, 2023.  (REUTERS/Thomas Peter / Reuters Photos)

The Brazilian Trade and Investment Promotion Agency (ApexBrasil) said the new arrangement is expected to "reduce costs" and "promote even greater bilateral trade and facilitate investment." 

China is Brazil’s largest trading partner, accounting for more than a fifth of all imports, followed by the United States, according to the latest figures. China is also Brazil’s largest export market, accounting for more than a third of all exports. 


China overtook the United States as Brazil’s top trading partner in 2009. Today, Brazil is the largest recipient of Chinese investment in Latin America, driven by spending on high-tension electricity transmission lines and oil extraction. 

Officials from both countries reached a preliminary agreement to ditch the U.S. dollar in January and the deal was announced after a high-level China-Brazil business form in Beijing. 


President of the Brazilian Export and Investment Promotion Agency (ApexBrasil) Jorge Viana attends the Brazil-China Business Seminar in Beijing, China, on March 29, 2023. (REUTERS/Thomas Peter / Reuters Photos)

Brazilian President Luiz da Silva, sworn in on January, has moved to strengthen ties with Beijing after a period of rocky relations under his predecessor, Jair Bolsonaro, who used anti-China rhetoric on the campaign trail and in office. 


Brazil’s leftist president was scheduled to visit Beijing last weekend by had to cancel his trip after contracting pneumonia. A delegation composed of ministers, senators, lawmakers, and hundreds of business people – including more than 100 from the agricultural sector – had been set to accompany Lula during his first state visit since taking office. 

The Associated Press contributed to this report.

Hannity: We have never seen this in history

Thursday, March 30, 2023

SES, Intelsat in Talks Over Potential Merger 

Satellite-services provider SES SA said it is holding discussions with Intelsat SA over a potential merger to create a satellite operator giant that would compete with Elon Musk's Starlink service.

The Luxembourg-based company made the disclosure on Wednesday, saying there can be no guarantee that a transaction would materialize at this stage. Bloomberg first reported that the two companies were in talks.

Last year, Paris-based Eutelsat Communications SA agreed to acquire the U.K.'s OneWeb Global Ltd. for $3.4 billion, a vote of confidence in an increasingly competitive sector that has seen the likes of Elon Musk and Jeff Bezos pour billions of dollars into space infrastructure.


Write to Mauro Orru at; @MauroOrru9

EIA: US crude inventories down 7.5 million bbl 

US crude oil inventories for the week ended Mar. 24, excluding the Strategic Petroleum Reserve, decreased by 7.5 million bbl from the previous week, according to data from the US Energy Information Administration.

At 473.7 million bbl, US crude oil inventories are 6% above the 5-year average for this time of year, the EIA report indicated.

EIA said total motor gasoline inventories decreased by 2.9 million bbl and are about 4% below the 5-year range for this time of year. Finished gasoline inventories increased, while blending component inventories decreased last week. Distillate fuel inventories increased by 300,000 bbl and are about 9% below the 5-year average for this time of year.

Propane-propylene inventories decreased by 2.5 million bbl and are about 34% above the 5-year average for this time of year, EIA said.

US refinery inputs averaged 15.8 million b/d for the week ended Mar. 24, about 437,000 b/d more than the previous week’s average. Refineries operated at 90.3% of capacity.

Gasoline production increased, averaging 10.0 million b/d. Distillate fuel production increased, averaging 4.6 million b/d.

US crude oil imports averaged 5.3 million b/d, down 847,000 b/d from the previous week. Over the last 4 weeks, crude oil imports averaged 6.0 million b/d, 5.8% less than the same period last year. Total motor gasoline imports averaged 873,000 b/d. Distillate fuel imports averaged 146,000 b/d.

World's most important oil price is about to change for good

Photo: Bloomberg 

  • US oil to be added to Dated Brent benchmark from June cargoes
  • Dated Brent helps set price of around two-third of world's oil

After years of wrangling, the world's most important oil price is about to be transformed for good, allowing crude supplies from west Texas to help determine the price of millions of barrels a day of petroleum transactions.

The shift is because the existing benchmark, Dated Brent, is slowly running out of tradable oil for it to remain reliable. As such, its publisher S&P Global Commodity Insights — better known by traders as Platts — has been forced to make a dramatic overhaul.

Its switchover was fraught with controversy and caused a lot of stress among physical oil traders. But it was necessary. BP Plc at one stage said that Dated Brent was subject to "increasingly regular dislocations."

But the future of Dated is now set. From cargoes for June onward, West Texas Intermediate Midland, oil from the Permian will become one of a handful of grades that set the Dated benchmark.

Here's a look at what matters as the transition gets closer.

1. Why does it matter?

Dated, as it's commonly known by oil traders, helps to set the price of about two-thirds of the world's oil and even defines the price of some gas deals.

Oil producing states will often sell their barrels at small premiums or discounts to Dated, so the precise mechanics of how it is formed matter to them. In addition, the benchmark lies at the center of a complex web of derivatives, ultimately shaping Brent oil futures that get traded on exchanges.

Dated affects a host of oil prices, so even crude in Dubai could feel the effects, according to Adi Imsirovic, a veteran oil trader and senior research fellow at the Oxford Institute for Energy Studies.

2. Exactly what's happening?

Traders will be able to offer WTI Midland for sale from the US Gulf Coast. It will be delivered into Rotterdam and then price will be netted back using a freight adjustment factor as if it's shipped from the North Sea.

By following a careful process, Platts will evaluate if the oil is being offered at a higher or lower level than five existing grades that set Dated — Brent, Forties, Oseberg, Ekofisk or Troll.

If Platts judges that WTI Midland is the most competitive price on offer — or actually sold — then it could set Dated.

So WTI Midland might then influence the price a seller of an Atlantic Basin barrel charges a refinery in China.

3. How will price discovery work?

Imagine the existing Dated grades, which go under the acronym BFOET, are at $80 a barrel.

A trader might pick up a cargo of WTI Midland at $79 from a terminal the US Gulf with $2 added delivery cost to Rotterdam — more than 6,000 miles and around 17 days sailing away.

Platts would need to make that delivered cargo like-for-like against the existing BFOET grades, which are transacted on a so-called Free on Board, or FOB, basis in the North Sea.

To do that, it will use what it calls a freight adjustment factor, deducting the estimated cost of transportation across the North Sea to Rotterdam. If that were to be $1 a barrel, then the implied FOB price of WTI Midland in the North Sea would be about $80.

The process will place an emphasis on Platts's assessments of tanker costs. 

4. What's the timeline?

Some changes are already getting underway. In February, Platts began assessing forward prices based on the new assessment. Real cargoes of crude from the US will be allowed for inclusion from early May.

The expiry of the May Brent futures contract at end-March will rely on some trades of a June Brent exchange of futures for physical contract, which will take the changes into account.

Those key derivatives tools, along with the futures market, will determine the basis price of physical Dated Brent for June.

An important detail in the coming weeks is just how much trading of forward Dated Brent will pick up. So far, twelve entities have conducted transactions based on the new terms, according to Platts. 

Ultimately these deals will define something called the Brent Index, a once-a-month price published by ICE Futures Europe that's used for the cash settlement of futures.

"Without a forward market, there's no way to financially settle the ICE Brent contract," said Kurt Chapman, a veteran oil trader and ex-head of crude at Mercuria Energy Group, who retired in 2018 after almost three decades on the front lines of global oil trading. 

5. Will the Dated be better?

Assuming traders take to the adjustments, it will be transformative in terms of the underlying volume of oil that can be transacted.

In March alone, around 60 tankers hauling around 1.8 million barrels a day of oil were expected to arrive in Europe, the highest since 2016, according to data compiled by Bloomberg.

Something like 1 million barrels a day of WTI Midland will theoretically be eligible for inclusion in Dated, although the volumes may be marginal until the trading of new Dated picks up. 

6. What are the main concerns?

No two crudes are identical and eventually Platts will have to evaluate precisely how WTI Midland compares with other grades within BFOET.

Some say it is superior because of its density and sulfur levels.

However, some European traders have also expressed worries that the properties of WTI Midland cargoes may not match up to what was stipulated when it traded. That's because WTI is actually a blend of different crudes. 

It would be a problem if a cargo of oil — bought or sold with a view to setting a global benchmark underpinning prices globally — were found to have a flaw.

US terminal operators say there's not much to be concerned about. They say that the 11 terminals approved by Platts that will send crude are all able to assure consistently high quality to suit Dated.

Another issue is the cargo sizes that will be allowed to be included. At 700,000 barrels, they do not match up to the reality of current oil trading of US oil. 

There has been a flood of supertankers bringing 2-million-barrel cargoes across the Atlantic. Those wouldn't qualify for inclusion in setting the Dated.

Finally, the BFOET grades all come with their own loading programs with each consignment given its own unique identifier. That gives traders clear visibility on the supply of oil. That's not yet the case for WTI Midland and could cause some uncertainty about how many cargoes are being offered.

— With assistance by Sherry Su and Sheela Tobben

Disclaimer: This article first appeared on Bloomberg, and is published by special syndication arrangement.

Mexican president proposes tougher mining laws, shorter concessions

 Mexican Network of People Affected by Mining blasts mining law reform

Mexican President Andrés Manuel López Obrador. (Image by Gobierno Danilo Medina, Flickr). 

The Mexican government’s proposed overhaul of mining laws, including shorter concessions and tighter rules for permits, drew a quick warning from industry leaders who fear it could undermine the sector’s growth prospects.

President Andres Manuel Lopez Obrador offered the draft reform on Tuesday to lawmakers in the lower house of Congress, which would sharply reduce the length of mining concessions to 15 from 50 years.

Mexico, a major mining country for decades, is the world’s top primary silver producer, as well as a top 10 gold and copper miner.

The initiative, which still must pass various legislative steps before it could be enacted, would also add new requirements to obtain mining and water permits, establish a new obligation to disclose mining impacts, and require miners to give back at least 10% of the profits to communities.

The country’s mining chamber Camimex warned that changes contemplated in the draft could provoke “strong repercussions” for the industry, stressing in a statement late on Tuesday that it continued to analyze the proposal.

Since he took office in late 2018, Lopez Obrador has refused to offer any new mining concessions, arguing that too many had been granted by previous governments.

Last year, the president championed the nationalization of the country’s nascent lithium industry, favoring a newly created state-run producer to mine the coveted battery metal, in another move mining sector analysts see dampening investor appetite.

Shares in precious metals miner Industrias Penoles fell more than 3% on Wednesday, after jumping more than 5% the day before, while Compania Minera Autlan dipped nearly 2%.

Leading copper producer Grupo Mexico advanced 0.73%, marking its third consecutive day of gains.

In its statement, Camimex expressed hope the upcoming debate over the proposal will incorporate industry concerns, adding it expects “a broad, inclusive and informed legislative discussion.”

(By David Alire Garcia, Valentine Hilaire and Noe Torres; Editing by Richard Chang)

Wednesday, March 29, 2023

$11 Trillion Investor Group Urges Members Not To Fund New Oil And Gas Projects 

The Net-Zero Asset Owner Alliance, a group made up of members from the banking, insurance, and investment sectors with $11 trillion of assets under management, called on its members on Wednesday to align their oil and gas policies to a 1.5-degree Celsius pathway, which cannot be achieved if there are new upstream infrastructure investments in new oil and gas fields.

“On private asset investment in new unabated oil and gas infrastructure, investors, including Alliance members, shall align with credible 1.5°C net zero scenarios. This cannot be achieved if there are new upstream infrastructure investments in new oil and gas fields,” the alliance said in a statement.

The alliance, in which 85 major banks and institutional investors are represented, issued a new position on the oil and gas sector today, expecting its member investors to adopt policies that align with these positions on infrastructure investments, or show how existing policies already align.

The investor group also called on oil and gas producers and their customers to set science-based, absolute- and intensity-oriented emissions targets covering Scope 1, 2, and 3 greenhouse emissions that are aligned with 1.5°C or limited overshoot scenarios.

“How energy is provided and consumed must therefore dramatically change. This includes the need to phase out non-renewable sources like oil and gas in many, if not most, of its current uses,” said Günther Thallinger, Allianz SE Board Member and Chair of the Net-Zero Asset Owner Alliance.

Under pressure from ESG trends and shareholders, some banks have announced in recent months tougher rules on the financing of fossil fuels.

ING, for example, is further restricting financing to the oil and gas industry, reducing the volume of traded oil and gas it finances and no longer financing midstream infrastructure for new oil and gas fields, the Netherlands-based bank said earlier this month. Last year, ING said it would aim to grow new financing of renewable energy by 50% by year-end 2025 and would no longer provide dedicated finance to new oil and gas fields.

Barclays has said it will no longer provide financing to oil sands companies or oil sands projects and tightened conditions for thermal coal lending in an updated policy, which fell short of announcing overall pledges or targets in funding oil and gas. 


By Tsvetana Paraskova for

U.S. gas producers skimped on price hedges and now face a reckoning

A Chesapeake Energy Corp worker at a drilling site on the Eagle Ford shale near Crystal City, Texas

A Chesapeake Energy Corp worker walks past stacks of drill pipe needed to tap oil and gas trapped deeply in rock like shale at a Chesapeake oil drilling site on the Eagle Ford shale near Crystal City, Texas, June 6, 2011. REUTERS/Anna Driver/File Photo 

HOUSTON, Feb 14 (Reuters) - A rout in natural gas prices will hurt first-quarter earnings and cash flows at gas producers as hedges - the industry's version of price insurance - were inadequate to offset the expected losses, analysts and industry experts said.

Producers starting the year with fewer hedges than historically will have to sell more gas at the market rate of about $2.45 per million British thermal units (mmBtu), below the breakeven prices for producing gas in some regions, and that may force some companies to reduce drilling and put off completing wells.

Hedges, or contracts that lock in prices for future output, help producers protect cash flows against price swings, helping them drill and complete wells - crucial at a time when Europe has looked to the United States for gas.

U.S. prices for the heating fuel traded as low as $2.34 per mmBtu this month, down 76% from last year's August peak and the lowest level since April 2021, on mild winter weather in North America and on weaker exports.

The low levels of hedging would drain cash flow as market selling prices are low, said Matt Hagerty, senior energy strategist at FactSet's BTU Analytics.

About 36% of 2023 gas production was hedged at the end of September, according to consultancy Energy Aspects, which tracked 40 publicly traded gas producers. That percentage was down from 52% a year earlier.

Producers entered in to only two to three swap deals per month from April to October last year, said David Seduski, natural gas analyst at Energy Aspects, referring to a type of hedge. He called that amount "incredibly minimal" and said it compared with 30 to 50 such trades per month in 2021.

A rally in prices in 2022 after Russia's invasion of Ukraine forced a lot of producers already hedged at lower prices to take on hedging losses. That may have encouraged them to hedge less.

"Last year was pretty jarring for folks, who weren't ready for the uptick in price. A lot of folks probably sold off those hedges and wanted to be exposed to the upside and might see themselves in the predicament they're in now," said Trisha Curtis, chief executive of energy consultancy PetroNerds added.

EQT Corp (EQT.N), the top U.S. producer of natural gas, last month said it expects a $4.6 billion loss on derivatives for 2022, and net cash settlements of $5.9 billion. No. 2 producer Southwestern Energy Co (SWN.N) posted a $6.71 billion loss on derivatives for the first nine months of 2022.


Some companies have let their hedges expire, increasing exposure to current prices. Antero Resources Corp (AR.N) said in October that the vast majority of its hedges would roll off by Jan 1.

Another type of hedge, known as a three-way collar, could backfire because of the extent of the fall in prices, analysts said. These transactions have a producer buy an agreement to sell natural gas at one price, called a put, while also selling a put at a lower price in hopes of pocketing the premium from its buyer.

Effectively, this is a calculated bet that gas will fall to a certain level and no further. But when it falls below the predicted lower price, it takes away some of the benefits of the hedge.

Chesapeake Energy Corp (CHK.O), for example, bought puts for 900 million cubic feet at $3.40 per million cubic feet (mmcf), while also selling puts for $2.50 mmcf for the first quarter, according to a November presentation.

Were gas prices to average $2.36 per mmcf, the company would pay out 14 cents per mmcf, reducing the gains from the hedge.

Antero and Chesapeake did not respond to a request for a comment.

Denver-based Ovintiv Inc (OVV.N), previously Encana, also said it had sold puts for 400 mmcfpd at $2.75 per mmcf for the first quarter of 2023, according to a November press release. That would erode the gains from the hedges by about 39 cents per mmcf.

On the other hand, companies that locked in higher prices on average during the run-up in prices late last year could see gains, Rystad Energy senior analyst Matthew Bernstein said.

While overall hedging was lower, the average $3.16 per mmBtu was higher than a year earlier, he added. EQT, for example, has hedged about 58% of its total production at an average of about $3.40 per mmBtu, higher than current market prices.

Ovintiv and EQT did not immediately respond to a request for a comment.

Reporting by Arathy Somasekhar in Houston Editing by Matthew Lewis

Investments in renewable energies must quadruple to meet climate target -IRENA 

BERLIN, March 28 (Reuters) - Global investments in energy transition technologies must more than quadruple annually to stay in line with commitments made under the Paris climate accord, the International Renewable Energy Agency (IRENA) said on Tuesday.

Investments in renewable energy technologies reached a record of $1.3 trillion last year but that figure must rise to around $5 trillion annually to meet the key Paris accord target of limiting temperature increases to 1.5 degrees Celsius (2.7 Fahrenheit) above pre-industrial levels, IRENA said.

In total, the world needs around $35 trillion for transition technology by 2030, including improving efficiency, electrification, grid expansion and flexibility, IRENA said.

Renewable energy deployment must grow from around 3,000 gigawatts annually today to over 10,000 GW in 2030, IRENA said, adding that more equality is needed in renewable expansion between industrial and developing countries.

New renewable energy projects in China, the European Union and the United States accounted for two thirds of installed capacity last year, while Africa accounted for only 1% of renewable capacity installed.

“A fundamental shift in the support to developing nations must put more focus on energy access and climate adaptation,” IRENA’ Director General Francesco La Camera said, calling on financial institutions to direct more funds towards energy transition projects with better conditions.

IRENA called for directing planned fossil fuel investments -around $1 trillion of fossil fuel investments per year by 2030 - toward renewable energy technologies and infrastructure. (Reporting by Riham Alkousaa; Editing by Sharon Singleton)

[Full Ver.] North Korea stages massive military parade at midnight

Sir Christopher Chope

Tuesday, March 28, 2023

Analysis-Iraq's ambition to match Saudi oil output is out of reach 

LONDON (Reuters) - Iraq's oil output and capacity may peak following growth of around 25% over the next five years, analysts said, falling short of 2027 targets and ending a long-standing ambition to rival the output of top OPEC producer Saudi Arabia.

Political infighting has cost Iraq the opportunity to invest in growing output more quickly. As the energy transition gathers pace, it means Baghdad may never be able to cash in the hundreds of billions of barrels it has in the ground, even with the efforts of the country's new energy minister to attract investment.

Since 2016, Iraq's output has stalled at around 4.5 million barrels per day (bpd).

Before then, capacity grew rapidly as the government opened up the sector in 2009 and international oil companies revamped the country's biggest oilfields.

GRAPHIC: Iraq's annual average crude oil production-

Growth slowed in part because Iraq agreed to cap output under supply policy agreed with the Organization of the Petroleum Exporting Countries (OPEC) and allies, a group known as OPEC+.

Iraq's Oil Minister Hayan Abdel-Ghani, who took office in October, plans to update Iraq's oil production strategies to meet local needs while complying with the OPEC+ agreement, oil ministry spokesman Asim Jihad told Reuters.

It is too early for the new government to talk about any significant increases in Iraq's oil production outside the OPEC+ agreement, Jihad said. Under the agreement, Iraq's production target is 4.43 million bpd until December.

As a result, Iraq has shifted focus to the refining and gas sectors and lowered capital expenditure in the oil sector, analysts at FGE consultancy and Rystad Energy told Reuters.


For the oil sector, the country has repeatedly delayed a target to reach 7-8 million bpd capacity, from the current 5 million bpd. The previous government said last year it hoped to reach the higher levels by 2027.

Some energy industry consultancies forecast that Iraq may never reach them.

Capacity would peak and plateau at 6.3 million bpd by 2028 before declining, Iman Nasseri, managing director for the Middle East with FGE consultancy, said. Politics, security and the investment environment were all contributing to prevent Iraq from pushing output higher than that, he said.

"We think Iraq's current target looks hard, if not impossible to achieve," Nasseri said.

Rystad Energy expected production to be limited to 5.5 million bpd by 2027 as a result of midstream growth limitations and because projects that are crucial to boosting output are stuck.

Two decades after the war began, the current targets and the even lower forecasts are far off Iraq's post-war goal to take capacity to 12 million bpd.

The ambition was scaled back in 2012 after international oil companies operating in Iraq negotiated lower output targets for their fields because of low recovery factors, high natural decline rates and because Iraq was not investing enough in infrastructure, analysts said.

The major oil companies had also hoped Baghdad would improve the terms of technical service contracts (TSCs). That never happened, and companies such as ExxonMobil Corp and Royal Dutch Shell Plc left.

GRAPHIC: Iraq’s revised production plateaus-


Analysts and industry insiders say the problems are above the ground rather than in the geology below, which has significant unexplored capacity, and include repeated changes to government, political infighting and red tape.

Successive governments failed to sign off on Iraq's fifth licensing round in 2018. Six deals out of eleven oil and gas blocs on offer were eventually signed at the end of February, marking long-awaited reforms to the conditions of operating in the country.

The beneficiaries were not the international oil companies, but UAE firm Crescent Petroleum and two Chinese companies.

A source close to the Iraq energy industry who could not be named because they were not authorised to speak to the press said the contracts awarded pay royalties upfront and link revenues to oil prices.

Abdel-Ghani's decision to sign the deals four months after his appointment may show a new resolve in government to cut deals more attractive to international energy companies, the source said. Still other issues remain.

A large-scale seawater treatment project needed to boost output at the southern oilfields through water injection, has been stalled for over a decade because of haggling over terms.

French oil major TotalEnergies is the latest to take on the project as part of a $27 billion deal to build four oil, gas and renewable projects over 25 years.

TotalEnergies CEO Patrick Pouyanne said this month contractual disagreements were unresolved.

"Iraq is not the easiest place to invest with all risk," Pouyanne said.

The water project would boost output at the five Iraqi fields by 2 mln bpd of the 2.4 mln bpd growth needed to reach Iraq's 2027 targets, according to Rystad data and Reuters research.

But completion before 2027 is unlikely, Rystad's vice president of Middle East upstream research Aditya Saraswat said.

Iraq's oil minister this month revived seven investment opportunities in Iraq's refining sector.

Even if Abdel-Ghani manages to find companies interested in those projects, Iraq's refining potential only allows 500,000 bpd of crude output growth and this would take time, Saraswat said.

Meanwhile, Iraq's southern export capacity has stalled at around 3.2-3.3 mln bpd for the last year following delays to infrastructure upgrades at its Gulf ports, data from state-owned marketer SOMO showed.

GRAPHIC: Iraq's crude exports from Basra-

(Reporting by Rowena Edwards in London, Maha El Dahan in Dubai, and Ahmed Rasheed in Baghdad; Editing by Simon Webb and Barbara Lewis)

Iraq and UAE Spearhead Downstream Expansion 

Oil markets have been affected by financial market challenges, inflation, and the war in Ukraine. Nevertheless, Arab Gulf countries remain resolutely optimistic, evidenced by new refinery and storage plans being developed in Iraq and the UAE.

This week, Iraqi minister of oil Hayan Abdul Ghani said that Baghdad has invited investors to set up seven new oil refineries throughout the country. Ghani said also that bidding has opened for three refineries today, while offers for three other ones are expected on April 2.

Ghani also reiterated that the new investments “constitute a shift in the government’s strategy towards encouraging foreign investment in oil refining and opening new horizons for international companies and the local private sector in this industry”.

Sources have indicated that the first three refinery projects entail a 50,000 bpd refinery in the Southeastern Maysan Governorate, a 70,000 bpd refinery in the Nineveh Governorate in North Iraq, and a 30,000 bpd refining unit in Basra. The April 2 offers are for a 50,000 bpd refinery in the Southern Dhi Qar Governorate, a 100,000 bpd refinery in Wasit (East Iraq), and a 70,000 bpd refinery in Muthanna (South Iraq). The seventh refinery project is slated to be for a 70,000 bpd refinery in the Western Al Anbar Governorate.

The refinery expansion strategy comes at a time when Iraq is still struggling to adhere to its OPEC quotas. State-owned Iraqi oil marketeer SOMO reported that in February 2023, Iraq produced around 4.34 million bpd, a small change from the previous month, and still 92,000 bpd below official OPEC quota levels.

In January 2023 production levels also were around 100,000 bpd below OPEC production quota, while December 2022 levels were at 4.43 million bpd. The main underlying reason for the current low production levels is the maintenance work taking place at the 400,000 bpd West Qurna 2 oil field. The shortfall however contradicts official statements made in January 2023 that other Iraqi oilfields would be able to compensate for lower production at West Qurna 2.

A more positive development this month is the rapprochement between Baghdad and the KRG, which have been at loggerheads about oil revenues from Iraq’s northern oil operations. According to Iraqi PM Mohammed Shia’ Al Sudani, Baghdad and the KRG government have reached an agreement to end the Baghdad – Erbil dispute over the Kurdistan region’s oil revenues. Al Sudani stated to the press that the Kurdish oil revenues will be put in a single account that both the PM and the Kurdistan PM will have control over.

And the stakes in Iraq’s north are huge. Often dubbed as one of the last oil frontiers, the lifting cost for oil remains the lowest in the world at around U$2-3 per barrel, on a par with that of Saudi Arabia, and reserves are vast.

Genel, a major partner working in the Kurdish region oil and natural gas industry, has reported that year-end 2022 gross 2P reserves at its Tawke license (Genel holds 25% working interest) are 327 million barrels. According to DeGolyer and MacNaughton international petroleum consultants, production was 39 million bpd in 2022 with an upward technical revision of 9 million barrels.

Through implementation and observation of the performance of phase 1 of the Tawke field Enhanced Oil Recovery (EOR) project, 11.7 MMbbls out of 23.3 MMbbls were moved from 2C resources into 2P reserves.

Meanwhile, at its Taq Taq concession (44% working interest, joint operator), gross 2P reserves are 24 million barrels as of end-2022 (26 million barrels at end-2021) after producing 1.6 million barrels according to McDaniel & Associates independent assessment.

And at its Sarta concession (Genel 30% working interest, operator) Genel’s estimate for gross 2P reserves is 9 million barrels at the end-2022 mark (32 million barrels at end-2021) following production of 1.7 million barrels after evaluation of results from appraisal wells and pilot production.

At the same time that Iraq is looking to give its downstream industry a nudge, the UAE’s plan to create a global oil hub at Fujairah looks much brighter. The Emirate hub is facing pressure due to the increased influx of Russian oil volumes, which has resulted in a strain on available storage and transit options. European markets have banned Russian oil, and Moscow has redirected its flows to Asia, providing an opportunity for Fujairah and other Emirati parties to take advantage.

VTTI Fujairah Terminals commercial manager Maha Abdelmajeed stated at the Fuel Oil Forum (FUJCON) that the terminal has seen a significant influx of Urals and naphtha, which he expects to last in the near future. However, existing tanks are already full, indicating that Fujairah’s storage capacity of 1.1 million cubic meters has been reached. Vessel data from 2022 shows that Fujairah has received around 12,500 vessels, with total volumes up by approximately 10%.

The Port of Fujairah’s BD Manager, Martijn Heijboer, expects a healthy appetite for new transit volumes and storage demand. Additionally, Fujairah is set to commission a dry bulk export facility soon, which will add approximately 18 million tons of aggregate handling capacity in Dibba.

By 2050, methanol and LNG are projected to have the top market share of alternative bunker fuels at Fujairah, followed by biofuels and ammonia. With these developments, Fujairah is expected to be well-positioned to become one of the world’s largest bunkering hubs.

Spurred by Permian, ExxonMobil Ramps U.S. Refinery Expansion Near Houston 

The largest U.S. refinery expansion in more than a decade has ramped up southeast of Houston at ExxonMobil’s Beaumont refining complex.

The $2 billion project, considered one of the largest in the world, bumped up capacity for transportation fuels by 250,000 b/d, to total 630,000 b/d-plus. The last big refinery expansion was in 2012.

“ExxonMobil maintained its commitment to the Beaumont expansion even through the lows of the pandemic, knowing consumer demand would return and new capacity would be critical in the post-pandemic economic recovery,” said President Karen McKee of ExxonMobil Product Solutions.

“The new crude unit enables us to produce even more transportation fuels at a time when demand is surging. This expansion is the equivalent of a medium-sized refinery and is a key part of our plans to provide society with reliable, affordable energy products.”

The refinery is connected to pipelines from ExxonMobil’s Permian Basin operations. Permian crude is processed at the Beaumont refinery, where the company manufactures finished products, including diesel, gasoline and jet fuel.

With the completion of the Wink-to-Webster crude line, which moves Permian oil to markets near Houston, as well as Beaumont pipelines, the new crude unit is positioned to further capitalize on segregated crude from the Permian Delaware sub-basin, where most of ExxonMobil’s production is underway.

As Permian oil output grew, construction on the Beaumont expansion began in 2019, involving 1,700 contractors. More than 50 full-time employees work at the expanded operations.

ExxonMobil’s integrated operations in Beaumont also include chemical, lubricants and polyethylene production. More than 2,000 people work for ExxonMobil in the Beaumont area, with operations accounting for around one in every seven jobs in the region.

Meanwhile, Calgary-based affiliate Imperial Oil Ltd. in January agreed to invest about $560 million to construct what could be the largest renewable diesel facility in Canada. The project at Imperial’s Strathcona refinery is expected to produce 20,000 b/d of renewable diesel, primarily from locally sourced feedstocks.

Through 2027, ExxonMobil plans to invest around $17 billion in lower-emission initiatives.

Refinery News Roundup: Companies in Africa Eye Refinery Investments 

Companies in Africa are eying investments in refinery upgrades and building new plants to meet more stringent specifications that are gradually being enforced throughout the continent and to avoid closures, according to panelists at the ARDA conference in Cape Town March 13-17.

A number of refineries have closed in recent years, including Zambia’s Indeni and South Africa’s Engen. Meanwhile South Africa’s Sapref and PetroSA have been mothballed while others remain idle, such as Ghana’s Tema and Cameroon’s Limbe.

Indeni halted in September 2020 and the closure was announced in December 2021. Engen closed in 2020 and is being converted into a terminal. Sapref was mothballed in 2022, and while the owners had aimed to find a buyer, a subsequent flooding of the site has made such option very unlikely, according to panelists.

Part of the reason cited for the closures was more stringent specifications.

In North Africa, Algeria is building the Hassi Messaoud refinery, while Egypt is carrying out upgrades at Assiut, El Nasr and Suez and building a 45,000 b/d CDU at Midor, panelists said.

There was a focus on the expected startup of Nigeria’s mega Dangote refinery. In Nigeria, NNPC’s three refineries — Kaduna, Port Harcourt and Warri — have all started repairs. The old Port Harcourt refinery was expected to come back onstream in the second quarter.

Meanwhile, Sonangol has been progressing with the construction of three greenfield refineries in Angola — Cabinda, Lobito and Soyo — and has also been considering an expansion of its Luanda refinery. Once the new refineries are commissioned, Sonangol expects to operate at around 425,000 b/d refining capacity.

Ghana’s new refinery, being built by the Sentuo Group, was expected to come online later this year or early 2024.

Uganda is expected to make the final investment decision on its Albertine Graben refinery in June.

Senegal’s SAR is looking at the expansion of its refinery, and Ivory Coast’s SIR is investing in expanding and also building new units which will help it improve the quality of its products.

In Gabon, Sogara is considering the construction of a hydrocracker to meet Africa’s objective of moving to cleaner fuel that complies with both AFRI 6 and Euro-V emission standards.

According to estimates by consultancy CITAC, the necessary refinery investments amount to around $15.7 billion.

Separately, as Africa’s energy demand and population grow, the continent is looking to ensure its energy security but also combine it with clean energy projects as the increased energy demand coincides with global energy transition efforts, according to delegates at the ARDA conference.

Energy demand is expected to grow by 45%-50% between 2020 and 2040, while the continent’s population will increase from 1.5 billion to 2.5 billion in 2050, data presented by delegates indicated.

The message conveyed by delegates was that growing demand for energy must be met with cleaner fuels. However, energy security was highlighted as the short-term priority.

Meanwhile, the region’s refinery capacity and utilization remain low, with total capacity estimated at around 2 million b/d and utilization slightly above 60% in 2021, data presented at the conference showed.

In other news, TotalEnergies has signed a 20-year, 260-MW renewable power purchase agreement with Sasol South Africa and Air Liquide Large Industries South Africa, the French energy company said. In April 2021, Air Liquide and Sasol launched a joint initiative to procure 900 MW of renewable energy for their operations in Secunda.

“TotalEnergies will develop a 120 MW solar plant and a 140 MW windfarm in the Northern Cape province to supply around 850 GWh/year of green electricity to Sasol’s Secunda site, located 700 km further northeast, where Air Liquide operates the biggest oxygen production site in the world,” it said.

The two projects are expected to be operational in 2025.

Monday, March 27, 2023

New York Close to Passing Statewide Gas Stove Ban on New Homes

Blue flames rise from the burner of a natural gas stove in Orange, Calif., June 11, 2003. (David McNew/Getty Images)

Blue flames rise from the burner of a natural gas stove in Orange, Calif., June 11, 2003. (David McNew/Getty Images) 

New York state is reportedly close to enacting the nation’s first legislative ban on gas stoves for most new construction, including single-family homes and commercial buildings.

Amid a statewide uproar over the plan, the Democrat-led state legislature is set to advance the move as part of Democrat Gov. Kathy Hochul’s $227 billion budget blueprint, which heavily focuses on phasing out the use of fossil fuels with a commitment to creating a “cleaner, healthier environment for future generations.”

If passed as is, the measure would prohibit the installation of “fossil fuel equipment” and building systems in the construction of new one-family and smaller multi-family homes, beginning on Dec. 31, 2025. The same prohibition would apply to new larger multi-family homes and commercial buildings starting on Dec. 31, 2028.

This policy means that any new apartments or homes built after the effective dates wouldn’t be allowed to have many other common fossil fuel household items, including furnaces, water heaters, and clothes dryers. The term “fossil-fuel equipment” actually covers a wide range of oil- or gas-powered plumbing, heating, lighting, insulating, ventilating, air conditioning, and refrigerating equipment, as well as elevators and escalators that run on fossil fuel.

Exemptions for commercial kitchens, laboratories, laundromats, hospitals, crematoriums, and critical infrastructure projects would be likely, the governor’s office stated last month.

The state budget is due at midnight on April 1.

Supporters of the plan hope that New York state would take the policies of California and Washington to the next level, Politico reported. Both of the Pacific coast states have banned gas stoves in new properties, but they did so by changing building codes instead of passing laws.

“All eyes are on us, and a lot of other states are looking to what New York does,” Pat McClellan, policy director at the New York League of Conservation Voters, told Politico. “If we prove it can be done and we have the political will to do this, it’s going to open the floodgates for other states to take action.”


The plan has triggered outrage among New York Republicans. Rep. Nick Langworthy (R-N.Y.), who chairs the New York State Republican Committee, called Hochul a hypocrite for not getting rid of gas stoves in her home in Buffalo and the governor’s mansion in Albany.

“Is it any surprise that Queen Kathy cooks on her gas stove when she flies around on private planes? New Yorkers are so sick of phony climate-warrior hypocrites and their ‘rules for thee but not for me,'” the congressman told the New York Post in January. “Our state is in a crime and economic free fall and she’s waging war on appliances.”

Lee Zeldin, a former Republican congressman from Long Island and a former candidate for governor, also took issue with the Hochul administration’s priorities.

“Other than the higher taxes, more crime, elimination of gas stoves, less freedom, lower test scores, and other doozies, life in Kathy Hochul’s New York is going just swell for her ‘apostles’ who haven’t left yet,” Zeldin wrote on Twitter on March 24.

Even some Democrats expressed skepticism, saying that forcing low-income families to go all-electric might make their lives harder.

“I would prefer that we incentivize electric buildings, either through tax credits or other proposals, rather than forcing it as an issue because there’s a lot of concern and angst in particular in western New York,” Assemblywoman Monica Wallace, a Democrat, told Politico. “We shouldn’t necessarily ban people from pursuing other options if that’s what they want.”

Dueling Studies

A recent study (pdf), backed by Colorado-based green energy advocacy group Rocky Mountain Institute, attributes nearly 13 percent of current childhood asthma nationwide to gas stove use. That’s similar to the percentage of American childhood asthma attributed to secondhand smoke exposure.

“Gas stove usage should be considered in multi-faceted asthma prevention approaches,” the researchers said. “Given that this exposure is preventable, our study demonstrates that known mitigation strategies will lessen childhood asthma burden from gas stoves.”

However, a comprehensive literature review (pdf) conducted by California consulting firm Catalyst Environmental Solutions found that cooking with gas is “not a significant determinant of residential indoor air quality,” concluding that many scientific studies on this topic have been used in California and other states to falsely claim that gas stoves harm respiratory health.

The researchers, whose research was paid for by the California Restaurant Association, said the asthma risk has more to do with the type of food cooked than the fuel used to cook it.

“Cooking typically relies on cleaner heat sources such as natural gas and electricity and occurs in settings in which care is taken to provide ventilation,” they wrote. “In these settings, the air emissions are due to the type of heat source (i.e., electricity and natural gas), the food being cooked, and the method of cooking.”

Column: Funds dump copper amid financial market turbulence

Funds cut copper exposure as Chinese impetus fades: Andy Home 

(The opinions expressed here are those of the author, Andy Home, a columnist for Reuters.)

Funds have dumped their bets on higher copper prices as the turbulence triggered by the collapse of Silicon Valley Bank continues to roil financial markets.

Early-year enthusiasm for copper as a proxy for China’s re-opening from stringent lockdown has succumbed to the contagious fear spreading from the banking sector to other risk asset classes.

The investment community has turned net short of CME copper for the first time in five months, while funds have cut their long exposure on the London Metal Exchange (LME).

Investors’ negativity towards Doctor Copper contrasts with the bullish headlines generated by the FT Commodities Global Summit.

Copper, currently trading in London at around $8,900 per tonne, could surpass its previous March 2022 price peak of $10,845 and hit $12,000 this year, according to Kostas Bintas, co-head of metals at trade house Trafigura.

Goldman Sachs is also expecting higher prices, arguing that the pace of global inventory draws could reduce visible stocks to an all-time low of 125,000 tonnes by the end of the second quarter.

Fund managers, however, are having none of it. Right now macro fear is overwhelming the micro picture.

Money manager positioning on the CME copper contract
Money manager positioning on the CME copper contract

Sell out

The CFTC Commitments of Traders reports are now fully up to date after the delays caused by the February cyber incident at ION Cleared Derivatives.

They show fund managers turning net short of the CME copper contract in early March for the first time since October last year.

The collective bear call flexed out to 9,837 contracts in the middle of the month before being trimmed back to 6,967 contracts as of March 21.

Driving that shift in positioning has been a sharp reduction in outright long positions, which have slumped from a January high of 78,429 contracts to a current 37,173. Short positions have built by only a relatively modest 6,823 contracts to 40,140 over the same time-frame.

The early-year bullish exuberance has clearly evaporated.

The LME’s positioning reports paint the same picture. Investment funds bought into copper in January, the net long position expanding from 11,830 to 32,397 contracts at the end of the month. By the middle of March it had shrunk back to 13,978 contracts.

If there are any copper bulls in the investor community, they are currently lurking in the “other financial” category of the LME’s reports, where positioning has gone from neutral at the start of January to a net long 7,819 contracts.

Fund positioning on the LME copper contract
Fund positioning on the LME copper contract

No buy-in

The speed of the positioning reversal in copper suggests short-term players are currently in the ascendant, trading copper against the dollar and gold, which has rallied strongly as a safe-haven bet.

Copper “remains dominated by the fx (foreign exchange) with HFT (high frequency traders) leaving a heavy footprint”, according to a Monday market update from LME broker Marex.

Conspicuous by its absence is any significant investor buy-in to the longer-term bull narrative in copper as an enabler of the energy transition.

“Although under-appreciated in the market today, green demand is here and already impacting fundamentals,” according to Goldman Sachs. (“Commodity Views,” March 23, 2023)

The bank expects clean energy demand for copper to rise by 30% year-on-year to 2.6 million tonnes in 2023, powered by an expanding electric vehicle sector and investment in solar energy.

Funds don’t appear to have heard the message.

Outright long positions on both London and US exchanges are small relative to 2020, when the copper price was rallying as first China and then the rest of the world emerged from the initial round of covid lockdown.

China’s recovery (again)

Fast forward three years and China is again coming out of lockdown after the lifting of zero-covid restrictions.

It’s been a stop-start recovery because it’s coincided with the national Lunar New Year holiday period, a seasonal low point for China’s manufacturing sector.

China’s net imports of refined copper were down by 13% year-on-year over the first two months of 2023. Inventory registered with the Shanghai Futures Exchange (ShFE) and its international branch, the International Energy Exchange (INE), mushroomed by 235,000 tonnes to 320,000 tonnes during January and February.

However, INE stocks have since stopped rising and ShFE inventory has fallen by 91,300 tonnes since the start of March.

Headline LME stocks are just 41,875 tonnes, excluding metal awaiting load-out. CME stocks last Thursday hit a nine-year low of 14,627 tons.

Bulls such as Trafigura and Goldman Sachs contend it’s a very thin inventory cushion if China rediscovers its copper mojo.

Funds bought into that bull narrative at the start of the year but have evidently switched focus to the dangers flowing from the banking crisis to Western metals demand.

Which, ironically, doesn’t mean that copper’s next major price move can’t still be generated by China.

(Editing by Jane Merriman)

Venezuela Arrests 21 in Corruption Crackdown, 11 More Wanted


FILE PHOTO: A man walks past a gas station with the logo of the Venezuelan state oil company PDVSA in Caracas, Venezuela December 23, 2016. REUTERS/Carlos Garcia Rawlins/File PhotoReuters 

By Deisy Buitrago and Marianna Parraga

CARACAS (Reuters) - An expanding anti-corruption probe in Venezuela has led to the detention of 10 officials and 11 businessmen, the country's attorney general said on Saturday, adding that arrest warrants for 11 more people have been issued.

The investigation, which began in October, is focused on state oil company PDVSA, a government entity supervising crypto currency operations, and the judiciary. This week, it led to the resignation of the country's powerful oil minister, Tareck El Aissami, who had served the government for two decades.

"We are talking about one of the most lurid plots in recent years, which involves officials, businessmen who benefited from corruption and young people - including the so-called mafia women - who participated in corruption and money laundering," Attorney General Tarek Saab told journalists in a press conference.

A Venezuelan entity supervising the use of crypto currency for official transactions was assigned oil cargoes for sale with no administrative control, Saab said. Many of the buyers did not pay for the oil correspondingly, he added.

Political Cartoons on World Leaders

PDVSA has accumulated $21.2 billion in commercial accounts receivable since 2020 including $3.6 billion potentially unrecoverable, documents viewed by Reuters showed this week, after turning to dozens of little known intermediaries to export its oil under U.S. sanctions.

The 21 people arrested face accusations of appropriation of public assets, money laundering, influence peddling and criminal association. Officials involved could also face charges of treason, the attorney general said.

Venezuela's President Nicolas Maduro, who said he has been directly overseeing the probe, this week appointed PDVSA's head Pedro Tellechea as new oil minister, delegating in him the supervision of the whole industry.

In the last five years, Saab's office has investigated 31 cases linked to corruption in Venezuela's oil industry, which provides most of the OPEC country's hard-currency revenue, leading to almost 200 people prosecuted.

(Reporting by Deisy Buitrago and Marianna Parraga; Editing by Marguerita Choy)

Copyright 2023 Thomson Reuters.