In July 2021, the European Commission did something that no other major governing body had ever attempted: It tied trade policy to climate policy. Reaching the European Union’s goal of cutting net greenhouse-gas emissions by 55% by 2030 will require the EU to reduce emissions both at home and beyond its borders. To this end, the Commission’s Fit for 55 initiative, a package of proposals aimed at meeting the bloc’s emissions-reduction target, includes a carbon border adjustment mechanism (CBAM) – an import tax designed to corral other countries into tackling climate change.
The CBAM would tax imported goods sold in EU markets on the basis of their carbon content (the emissions required to produce them), which depends on their material and energy inputs. The proposed levy is intended to address so-called carbon leakage, which occurs when businesses in the EU move production to non-member countries with less stringent emissions rules.
In other words, Europe would no longer ignore the climate effects of foreign goods. But while the measure could help to reduce emissions and level the competitive playing field for EU-based firms, the trade protectionism that it entails risks hurting developing countries.
The CBAM will initially apply to the highest-emitting industries most at risk of leakage – iron and steel, cement, fertilisers, aluminium, and electricity generation – and will likely be expanded to other sectors in the coming years. Currently, EU-made products in these industries are taxed under the domestic carbon price, but those from outside the bloc are not. If a country already has a domestic carbon price, the border tax will be lowered or waived; this is meant to encourage countries to tax carbon in their own markets. Those that cannot or will not institute a carbon tax will have to pay the full levy.
The EU tax will be phased in over the next four years. By 2023, importers will be required to report emissions embedded in the goods they import, though the tax on those emissions will not be imposed until 2026. The €1bn ($1.1bn) of annual revenue expected from the CBAM, as well as the €9bn in annual revenue expected from the EU Emissions Trading System from 2023-2030 and taxes on multinational corporations, will support the Union’s €750bn Covid-19 pandemic recovery fund. These new sources of revenue will embed EU priorities – including the green transition – in the bloc’s budget for the first time.
Though not yet approved, the proposed tax is already influencing the decisions of policymakers and companies in the EU’s trading partners. For example, Turkey and Indonesia plan to introduce carbon taxes to mitigate the CBAM’s effects on their economies. Turkey is highly exposed, because the EU accounts for 41% of its exports. Indonesia exports billions of euros’ worth of palm oil and chemicals to the EU – goods that could fall under a broader border tax. Adopting a domestic carbon price will allow them to avoid some or all of the CBAM and keep the tax revenues instead of transferring them to the EU.
Meanwhile, some EU-based companies in industries such as computer hardware are looking to reshore manufacturing operations ahead of the CBAM’s introduction. Their main motive does not reflect the cost of the tax so much as the likely complexity, bureaucracy, and unpredictability of the system. It is easier and cheaper for companies to relocate production to the EU and avoid the administrative hurdles that the CBAM could create.
Such shifts will be a win for the EU’s economy and the environment. And Russia’s invasion of Ukraine could accelerate the EU’s efforts to achieve greater economic self-sufficiency, not least by reducing its dependence on energy-intensive imports of Russian iron and steel.
But developing economies, which often depend on manufactured products, will likely experience an outflow of activity as firms relocate to the EU. Rather than addressing only carbon leakage and leaving developing countries to adapt as best they can, the EU should allocate part of the revenue from the proposed CBAM to help foster a just green transition for poorer countries.
It is not easy or cheap to decarbonise energy-intensive goods like cement and steel. But the EU could prevent negative knock-on effects for developing economies – not only by waiting for lower-income countries to introduce their own carbon taxes (which will be a challenge given their limited administrative capability in the field), but also by supporting those that need the most help to reduce their emissions.
Such support could be provided by dedicating resources and technology to improve the efficiency of industrial processes, financing renewable energy projects, and exempting the poorest countries from the CBAM where necessary. The EU should also dedicate part of the CBAM revenue to help developing countries adopt cleaner technologies – to produce greener cement in Vietnam or chemicals in Indonesia, for example – and thus reduce emissions in the long run.
Europe sees itself as a global leader in the race to net-zero emissions. By helping to finance the developing world’s green transition, the EU could mitigate the protectionist threat in its own climate agenda. – Project Syndicate

• Miriam Gonzalez Durantez is an international trade lawyer and guest lecturer at Stanford University. Calli Obern, a master’s candidate in international policy at Stanford University, is a research fellow at Ecospherics, an advisory firm focusing on environmental and national-security issues.

Human-induced climate change is causing dangerous and widespread environmental disruption and affecting the lives of billions of people around the world. According to the Intergovernmental Panel on Climate Change, the world faces unavoidable climate hazards over the next two decades. But, with average annual global greenhouse-gas emissions reaching their highest levels in human history between 2010 and 2019, we are simply not doing enough to limit global warming to 1.5C.
The IPCC report released in April recommended that the world rapidly reduce fossil-fuel supply and demand between now and 2050: by 95% in the case of coal, 60% for oil, and 45% for natural gas. But how can we possibly achieve such ambitious targets?
The answer is by switching to green hydrogen, which can be produced from all forms of renewable energy, including solar, wind, hydro, and geothermal. Green hydrogen is a zero-emissions fuel; when produced through electrolysis, the only “emission” is water. It is a practical and implementable solution that, by democratising energy, decarbonising heavy industry, and creating jobs globally, would help revolutionise the way we power our planet.
A rapid acceleration of the green-energy transition can also fundamentally alter the geopolitical landscape, since countries will no longer be powerful simply because of the fossil fuels they produce. In 2021, Russia provided 34% of Germany’s crude oil and 53% of the hard coal used by German power generators and steelmakers. Russian-piped natural gas was Germany’s largest source of gas imports in December 2021, accounting for 32% of supply. Since Russian President Vladimir Putin launched his horrific, unjust war in Ukraine in February, fossil-fuel exports to Europe have been earning Russia roughly $1bn a day.
But since the start of the invasion in February, European Union countries in particular have moved quickly to reduce their energy dependence on Russia, recently agreeing to ban all seaborne imports of Russian oil. These new sanctions against Putin’s war machine could cut the amount of oil the EU buys from Russia by 90% this year. The United States has declared a complete ban on Russian oil, gas, and coal imports, while the United Kingdom is phasing out imports of Russian oil by the end of 2022.
These policies have sent fuel prices soaring. But sharply higher prices have also highlighted the opportunity to drive down energy costs by investing in renewables and the production of green hydrogen.
New research suggests that green hydrogen will be competitive with fossil fuels over the next decade. The cost of green hydrogen is expected to decline significantly by 2025 and to fall to $1 per kilogram by 2030 in favourable locations such as Australia. For comparison, grey hydrogen, which is made using polluting liquefied natural gas, currently costs around $2 per kilogram.
Some advocate using LNG to “solve” the current energy-security crisis, but “natural gas” contains methane, and the IPCC says that we must reduce use of natural gas by almost 45% by 2050; adding more to the energy mix now would be a catastrophic mistake.
So, there is now a global race for green energy, and specifically for green hydrogen. Dozens of countries that have abundant renewable-energy sources can develop energy independence by producing green hydrogen at scale. And energy importers will not have to rely only on the few countries (such as Russia) that have a natural endowment of fossil fuels.
In a recent report, the International Renewable Energy Agency said that (green) hydrogen can bolster energy security in three main ways: by reducing import dependence, mitigating price volatility, and boosting energy systems’ flexibility and resilience through diversification. As technologies improve, the cost of green hydrogen will fall. We must do everything we can to accelerate this process.
Companies like Fortescue, where I am a board director, are investing significantly in green hydrogen and will help to replace Russian fossil fuels with green energy. Fortescue recently announced an agreement with Germany’s largest energy distributor, E.ON, to supply Europe with 5mn tonnes of green hydrogen a year by 2030 – the equivalent of one-third of the calorific value of the energy that Germany currently imports from Russia.
But while rapid changes in the energy and geopolitical landscape present a clear opportunity to address the energy and climate crises simultaneously by investing in green energy, there is a clear perception of unfairness when developed countries claim that relatively low-emitting developing economies need to shut down fossil-fuel use. Why should they risk slowing their development to address a problem they played no part in causing?
It’s a valid question. Policymakers will need to account for developing countries’ interests during the green transition and enhance funding and incentives for them to move to clean energy as the basis of industrialisation.
The world is clearly at a fork in the road. We can remain locked into a costly, polluting future that is hideously inefficient and empowers only a handful of fossil-fuel-rich countries. Alternatively, we can choose a green revolution of low-cost energy for all that keeps our future secure from pollution, global warming, and dictators. Given that green energy has the power to democratise global supply as more countries achieve energy independence, the choice is not difficult. – Project Syndicate

• Jean Baderschneider is a non-executive director of Fortescue Metals Group.

Oil giant Saudi Aramco’s chief on Tuesday blasted “unrealistic” energy transition plans, calling for a “new global energy consensus”, including ramped-up investments in fossil fuels to address painful shortages.
Speaking at a conference in Switzerland, Amin Nasser, head of the world’s biggest crude producer, lamented a “deep misunderstanding” of what caused the current energy crunch and said a “fear factor” was holding back “critical” long-term oil and gas projects.
“When you shame oil and gas investors, dismantle oil- and coal-fired power plants, fail to diversify energy supplies (especially gas), oppose LNG receiving terminals, and reject nuclear power, your transition plan had better be right,” he said.
“Instead, as this crisis has shown, the plan was just a chain of sandcastles that waves of reality have washed away.
“And billions around the world now face the energy access and cost of living consequences that are likely to be severe and prolonged.”
The primarily state-owned Saudi Aramco last month unveiled record profits of $48.4bn in the second quarter of 2022, after Russia’s invasion of Ukraine and a post-pandemic surge in demand sent crude prices soaring.
Yet even as it benefits from the current energy crisis, Riyadh has long complained that focusing on climate change at the expense of energy security would further fuel inflation and other economic woes.
With consumers and businesses in Europe facing soaring bills as winter approaches, the causes of the crisis run deeper than the Ukraine war, Nasser said Tuesday, asserting that the warning signs were “flashing red for almost a decade”. They include declining oil and gas investments dating back to 2014 and flawed models for how quickly the world could transition to renewable sources, he said.
The “energy transition plan has been undermined by unrealistic scenarios and flawed assumptions because they have been mistakenly perceived as facts”, Nasser said.
His proposed “new global energy consensus” would involve recognising long-term needs for oil and gas, enhancing energy efficiency and embracing “new, lower-carbon energy” to complement conventional sources. Nasser nonetheless said there should be no change in global climate goals.
Riyadh has come under intense outside pressure in recent months to ramp up oil production, including during a visit by US President Joe Biden in July.
So far it has largely rebuffed those appeals, co-ordinating with the Opec+ alliance it jointly leads with Russia.
Earlier this month the bloc agreed to cut production for the first time in more than a year as it seeks to lift prices that have tumbled due to recession fears.
Long-term, Saudi Arabia plans to increase daily oil production capacity by more than 1mn barrels to exceed 13mn by 2027.
Crown Prince Mohamed bin Salman has also tried to make environmentally friendly policies a centrepiece of his reform agenda.
Last year, Saudi Arabia pledged ahead of the COP26 climate change summit to achieve net zero carbon emissions by 2060.
Saudi Aramco, for its part, has pledged to achieve “operational net-zero” carbon emissions by 2050. That applies to emissions that are produced directly by Aramco’s industrial sites, but not the CO2 produced when clients burn Saudi oil in their cars, power plants and furnaces.

Amid a verbal row between Israel and Lebanon, developing the Karish natural gas field represents a way forward for exploiting smaller offshore hydrocarbon discoveries in Israel’s exclusive economic zone (EEZ). The field’s 1.75 trillion cubic feet (tcf) of reserves are much less than the estimated volumes in Israel’s two producing fields, Leviathan (35 tcf) and Tamar (7.1 tcf). But even before the recent sharp increase in gas prices, Energean, the Greek-British license holder for Karish, decided the best way to exploit the field was by linking its development to two other small fields in the area, Karish North and Tanin.

Key to this task is the Energean Power, a floating production storage and offloading vessel (FPSO) that took up position fifty miles off Israel’s northern coast last week and is due to start production in the third quarter of this year. The vessel will use multiple anchors in water 5,500 feet deep to maintain its position. Seabed equipment linking to the gas field below will then be connected by hoses to the FPSO. Once gas is flowing to the vessel, it will be processed onboard, cleaning it of oil products and water before it descends by other hoses to the seafloor and connects with a pipe that takes it ashore. Using a pressure control device close to the beach, it will then enter Israel’s gas grid to supply power stations. Meanwhile, the separated oil products and waste will be collected by a small tanker mooring alongside the FPSO every two weeks or so, and the separated water will be cleaned and pumped back into the sea.

In Israeli domestic political terms, the crucial advantage of the Energean Power is that it is not visible to local residents (read: voters). In contrast, the production platform for the Leviathan field is visible just a few miles offshore from the hilltop resort of Zichron Yaakov south of Haifa, leading to protests—though the tall chimneys of the nearby Hadera power station have escaped such complaints. As for Tamar, its platform is located out of sight thirteen miles off the coast of Ashkelon far to the south, but its gas still needs additional processing at the Ashdod onshore terminal. In terms of potential security threats, the existing facilities for Leviathan and especially Tamar are closer to the Hamas-controlled Gaza Strip.

Another plus for the Energean Power is that it can be connected with relative ease to additional fields in the area for which Energean holds the license, without the vessel needing to change location. The Karish North field is due to come online in the second half of 2023. Energean also judges that reserves in the “Olympus” area of Block 12 slightly further south will be commercially exploitable, though its latest drilling suggested only 0.28 tcf of reserves rather than the hoped-for 0.7 tcf. By carefully phasing such exploitation, the company hopes to maintain a steady production stream and offset the decline that occurs over the usual fifteen-year lifespan of an individual field.

In total, the Energean Power can handle 8 billion cubic meters (bcm) of gas per year. Setting aside the sometimes-confusing mix of metric and U.S. units of measurement represented by such figures, this amount will help meet Israel’s expanding demand for energy. For example, desalination alone consumes 10 percent of the country’s electricity. Eventually, surplus gas will be available for export, with Egypt as the first customer—though the purchase terms for Karish and Tanin do not permit Energean to export from those two fields.

The Lebanese Angle

Energean’s planning seems unaffected by Lebanon’s expanding claims for its EEZ, which encroaches on the Karish field. When tugboats moved the Energean Power into position last week, Hezbollah issued threats, and U.S. special envoy Amos Hochstein quickly visited Beirut to calm tempers.

From Israel’s point of view, Karish is firmly in its EEZ. Moreover, dealing with threats against its gas installations is nothing new—the Leviathan platform is in range of both missiles from Lebanon and rockets from Gaza. Israel’s main answer to this problem is deterrence, the implication being that any action or immediate threat against such installations would be dealt with either preemptively or through massive retaliation.

Israel and European Energy Demand

The volumes achievable from Karish and similar gas fields are significant for Israel but not in global terms. For comparison, Leviathan produces about 12 bcm per year and Tamar less than 10 bcm, while Europe’s annual demand for gas was around 400 bcm even before the Ukraine crisis, with Russia supplying more than 40 percent of that amount. Clearly, increased Israeli exports would have minimal impact on this imbalance.

Nevertheless, planners are considering ways to increase Israeli production. Leviathan volumes can grow, albeit with a commensurate increase in the size of its controversial offshore platform. Israel may also be able to export gas more widely than its current arrangements: by pipeline to Jordan (where 80 percent of electricity is produced by Israeli gas) and Egypt (whose apparently insatiable domestic energy market is not sufficiently fed by the country’s 75 tcf of gas reserves and estimated annual production of 65 bcm).

Currently, any exports further afield would need to be funneled via one of Egypt’s liquefied natural gas plants on the Nile Delta coast. Israel may eventually be able to use a floating LNG platform off its own coast to load specially built tankers with Leviathan gas, though rough seas in winter could make this approach infeasible. Another consideration is a potential pipeline to Cyprus, where an LNG vessel moored in port could supply the island’s modest domestic market while still leaving most of the Israeli product available for export further abroad. A proposal for a seabed line to take Israeli gas to Greece is effectively dead after the U.S. government signaled that the plan was logistically and commercially impractical.

Meanwhile, Israel, Egypt, and the European Union are expected to sign a memorandum of understanding on increasing gas exports, though it is difficult to see what immediate practical effect this will have. Israel’s Ministry of Energy will also open another round of bidding for licenses to explore in its EEZ. The degree of interest shown in this round will indicate how international energy companies currently regard the attractiveness of Israeli prospects.

Simon Henderson is the Baker Fellow and director of the Bernstein Program on Gulf and Energy Policy at The Washington Institute.

There is not much Qatar can do to alleviate Europe’s gas crisis in the short term due to contractual commitments, Qatari Energy Minister Saad al-Kaabi tells Energy Intelligence — but further out, in five to seven years, new Qatari LNG exports to Europe should be significant. In an exclusive interview, al-Kaabi said production from the Golden Pass LNG project in the US, where QatarEnergy partners with Exxon Mobil, is due on stream in 2024 and is “already earmarked for Europe.” Up to half of new output from Qatar’s 48 million ton per year North Field mega-expansion could also go West of Suez when it starts up from 2026. Al-Kaabi also serves as head of state-owned QatarEnergy, which is in active discussions with customers for the new supplies. Significantly, targeted contract durations are shorter than the 20-year deals seen in Qatar’s original LNG expansion, reflecting European reluctance to lock into gas supplies long-term. “I think 10-15-year deals are probably what are most acceptable to both sides. But for us, the long-term deal, it’s not just about duration, it’s about price,” he said. Even with such supplies, al-Kaabi expressed skepticism about Europe’s ability to completely wean itself off Russian gas. Europe will find it “very difficult” to completely forgo Russian pipeline gas for more than two winters. Despite storage, fuel switching and active efforts to expand LNG imports, “a quick fix” to the EU’s dependency on Russian gas does not exist.

Qatar’s North Field expansion is attracting enormous interest from foreign investors, with TotalEnergies tipped to become the first of the Phase-2 partners to be selected later this month. But investors in existing Qatari projects face a rocky ride when contracts on current joint ventures expire, as Exxon and Total discovered when their prized Qatargas-1 contract was not renewed last year. Al-Kaabi revealed that QatarEnergy came close to going it alone on the North Field expansion, too. Qatar, which is generating around 1 million barrels of oil equivalent per day of net output for Exxon, Total and Shell alone, is critical for the majors. However, “if there is no value, there is no partnership, very plain and simple,” al-Kaabi said. Even if joint ventures are maintained after expiry, terms will be tougher. For Exxon, which has stakes in nine of Qatar’s 14 trains, these contract renewals are especially strategic. Qatar knows the value of its LNG will likely drive a hard bargain. “An investment in Qatar is really an important downside-risk revenue maker” for partners, al-Kaabi said.

LNG is only part of a multifront, international investment drive now under way at QatarEnergy. Downstream, petrochemicals is a priority, with al-Kaabi touting QatarEnergy’s planned US project with Chevron Phillips Chemical as “the largest polyethylene plant.” It recently awarded construction contracts for a 1.2 million ton/yr blue ammonia project, also tipped to be the biggest of its kind. But its global upstream drive is most significant. There were doubters when the strategy launched, but QatarEnergy has been vindicated over the past year by major exploration success in Namibia. QatarEnergy, by virtue of sizable stakes in both Total and Shell discoveries, is poised to be the largest reserves holder in a significant new oil province — Total’s Venus discovery is described as the largest deepwater find ever. There have also been offshore gas discoveries in Cyprus and South Africa. And in Brazil, output at QatarEnergy’s offshore Sepia field is set to more than double to 400,000 barrels per day in the next couple of years.

Despite confidence in long-term gas demand, QatarEnergy is taking steps to ensure its place in the energy transition. It is investing heavily in greenhouse gas emission mitigation technology at projects. Over $250 million is being spent on such measures at the LNG expansion alone — principally carbon capture and storage (CCS) and solar power. Some 11 million tons/yr of CCS is planned by 2035. “From an overall value chain, Qatari LNG will be the least carbon footprint LNG you can get,” al-Kaabi said. “We think that our buyers, and our investors that have joined us in [North Field East expansion], see this as the Rolls-Royce of projects.” Transition pressures are feeding into the urgency for developing projects. “I am a believer that you need to monetize what you can because the market conditions change, and there is a competitive advantage to go ahead of others,” al-Kaabi stated.

مع وصول مفاوضات ترسيم الحدود البحرية إلى خواتيمها على الرغم من ضبابية الجواب الإسرائيلي الذي سيحمله آموس هوكشتاين إلى الدولة اللبنانية، يؤكد الخبير الدولي في شؤون الطاقة رودي بارودي لموقع “القوات اللبنانية” الإلكتروني، أن “منطقة حوض شرقي المتوسط    “Levantine basin” التي هي بقعة مثيرة ومعقدة للغاية لأسباب جيو ـ سياسية، تحتوي على آفاق إمكانية وجود كميات كبيرة من البترول والغاز لم يتم اكتشافها واستغلالها بعد، خصوصاً أن المنطقة تحتوي على الكثير من الاحتياطي النفطي الممكن الاستفادة منه”.

ويُضيف أن ما يؤكد هذا الأمر، هو نتائج مسح أكثر من 60 ألف كم من الخطوط الزلزالية الثنائية والثلاثية الأبعاد في منطقة حوض شرقي المتوسط فقط “Levantine basin” وتحديداً في لبنان، قبرص، إسرائيل حتى حدود مصر البحرية، وهي البلدان الموجودة حول حوض بلاد الشام، وذلك بين الأعوام 2002/2008 وأيضاً في العام 2016، (More than approximately 60,000km of 2D and 3D seismic lines)، والتي أظهرت أن هناك أكثر من 150 احتمالًا لوجود مكامن بترولية داخل مناطق المسح.

وفي هذا الاطار، أثبتت الدراسات التي أجرتها شركات Spectrum وPGS وTGS وNEOS نجاحها في مناطق معيّنة ولا يزال يتعيّن إثباتها في أحواض أخرى. ففي العامين 2008/2009، تم اكتشاف كميات من الغاز في المياه الإسرائيلية في حقلي تمار وليفياثان وأيضاً في حقل أفروديت القبرصي كما في حقل زهر في مصر العام 2015؛ علماً أن دراسات مركز المسح الجيولوجي الأميركي والتي أجريت في العام 2016 & 2010 (USGS) خلصت إلى أن الإمكانات غير المكتشفة تبلغ ضعف إجمالي ما تم اكتشافه من غاز (كما هو ظاهر في الخريطة المرفقة).

ويتابع، مع كل الاكتشافات الحديثة بما في ذلك الاكتشاف الذي أعلن عنه في حقل “كرونوس” في قبرص الأسبوع الماضي، يمكن ان نتحدث عن تقدير للكميات بأكثر من 52 تريليون قدم مكعب. كل هذه الاكتشافات التي تحيط بلبنان تؤكد أن هناك احتمالية عالية لاستخراج كميات تجارية من الغاز، وهذا ما تشير إليه وبشكل واضح العديد من التقييمات الجيولوجية التي أجرتها أهم الشركات العالمية في هذه الصناعة.

ويؤكد بارودي أنه “بناءً على العديد من النماذج المستقاة من الدراسات الجيولوجية الهيدروكربونية، كما على تحليل طبيعة باطن الأرض الصخرية، يمكن الجزم أنه يوجد ما يكفي من الموارد الطبيعية وبكميات كبيرة في شرقي المتوسط لا تزال غير مكتشفة وغير مستثمرة، لا سيما في المياه اللبنانية.

ويعتبر أن “الأهم في الموضوع أنه بعد 20 عاماً تقريباً توحّدت القيادة اللبنانية حول كيفية التعامل مع ملف يمكنه إنقاذ لبنان من المعاناة الاقتصادية والمالية التي يمرّ بها وأعني بذلك موقفهم الموحّد حول ترسيم الحدود البحرية مع إسرائيل”. ويشدد في السياق، على أن “لبنان يحتاج في أسرع وقت ممكن إلى إجراء العديد من الإصلاحات المطلوبة لإعادة إنتاج نظامه المالي والقضائي والاقتصادي، وفي حال ترافق الإصلاحات مع إبعاد ملف النفط عن المناكفات السياسية، سيعرف لبنان نهضة اقتصادية ومالية أكيدة ما يساعد على تطوير البنى التحتية التي هو في أمسّ الحاجة إليها ويُعيد الأمل إلى الشعب اللبناني وتزدهر قطاعات عدة ومنها القطاع المصرفي والتعليمي والاستشفائي”.

ويضيف، إذ إن كل هذه التطورات، ولا سيما التوصل مع إسرائيل إلى ترسيم واضح للحدود البحرية يحافظ على المصالح اللبنانية، يمكنه أن يساهم في معاودة شركات النفط التنقيب في البحر اللبناني، كما يساعد على تشجيع الشركات العالمية على التقدم إلى عمليات الاستكشاف النفطي سواء في البحر أو البرّ، ما يساعد في خلق جوّ اقتصادي مُريح يحتاجه لبنان.

ويقول في هذا الإطار، لا بد من شكر الجهود الحثيثة التي تقوم بها الإدارة الأميركية من أجل إيجاد حل عادل للنزاع الحدودي البحري مع اسرائيل.

ويتابع بارودي، على لبنان وفور الانتهاء من المفاوضات غير المباشرة مع إسرائيل، أن يعدّل إحداثيات المرسوم 6433 ويودعها لدى الأمم المتحدة ـ قسم شؤون المحيطات وقانون البحار DOALOS، كي يحافظ على حقوقه المكتسبة كما على إسرائيل أن تفغل الشيء نفسه.

أما بخصوص انسحاب الشركة الروسية “نوفاتيك” من تحالف شركات “إيني” و”توتال”، فيؤكد أنه “أمر طبيعي مع وجود العقوبات الأميركية على الشركة الروسية، إذ لا تستطيع الأخيرة أن تستقبل أو أن تحوّل أموالاً طالما أن نظام العقوبات يطاولها”.

ويؤكد بارودي، “نعم يستطيع لبنان الخروج من النفق المظلم، شرط أن تتكاتف الإرادات الحسنة للعمل على إنقاذه”.​

Russia defied expectations of a collapse in oil production following its invasion of Ukraine. But Moscow will have to redouble its efforts to find new buyers if it’s to keep output from shrinking in the coming months.

After plunging in the immediate aftermath of its offensive in February, Russian production has rebounded over the past three months as domestic refining boomed and Asian customers stepped in to take shipments shunned by Western buyers. Yet a looming European Union ban on most Russian crude, as well as a gathering economic slowdown, will strike a blow to the country’s producers.

“Russian oil companies have been enjoying the beauties of the summer season — soaring domestic demand and the absence of EU sanctions have allowed them to ramp up production,” said Viktor Katona, head of sour-crude analysis at data firm Kpler. “As we look into the immediate future, that is bound to change.”

Russian output of crude and condensate — a lighter type of oil — reached a wartime high of around 10.8 million barrels a day in July. Volumes may fall to about 10.5 million a day when the EU ban kicks in in December, Katona said. Analysts at Rystad Energy AS see some 10.1 million a day by year-end, while the International Energy Agency expects a slump of about 2 million a day by the start of 2023.

Russia’s Energy Ministry didn’t respond to requests for comment on its outlook for future production as the EU restrictions approach.

The embargo, which will apply to imports of seaborne crude and most piped supplies from Dec. 5, is set to remove some 1.3 million barrels a day from the European market, IEA estimates show. A ban on oil-product imports follows on Feb. 5, likely cutting a further 1 million barrels a day, the IEA said last week.

Many traditional buyers are already refusing to take Russian barrels, prompting Moscow to sell to customers in Asia, often at a substantial discount. Russia has this year raised its seaborne crude flows to the region by almost 800,000 barrels a day, according to vessel-tracking data compiled by Bloomberg.

But the country can’t count on Asia to mop up all the spare barrels once the EU ban comes into effect as the region is already saturated with Russian crude, according to analysts at Kpler, Rystad and Moscow-based BCS Global Markets.

“In the short term, Asia is already taking almost all that it can,” said Ron Smith, an analyst at BCS.

A loss of Russian production equal to all its current seaborne exports to Europe is a worst-case scenario and unlikely to materialize, said Sergei Vakulenko, an independent expert with more than 25 years’ experience in the Russian oil industry. He expects that traders globally will be eager to find buyers for the extra Russian volumes, given a dearth of spare production capacity elsewhere.

Vakulenko sees Russian output remaining roughly flat until year-end, a view shared by Kirill Bakhtin, a senior oil and gas analyst at Sinara Bank.

“We expect more or less stable production of Russian liquid hydrocarbons in the amount of 10.8 million barrels per day until February 2023,” thanks to successful efforts to redirect oil from Europe to Asia, Bakhtin said.

In the first couple of weeks this month, Russia’s daily crude oil and condensate output averaged about 10.47 million barrels a day, according to a Kommersant newspaper report Monday. The 3% drop from July is likely driven by seasonality and not by long-term factors such as sanctions, with much of the lower supply coming from a group of smaller producers, including gas giant Gazprom PJSC, according to the Energy Ministry’s CDU-TEK data seen by Bloomberg.

Refinery Demand

Russia’s seaborne exports have recently slid from their spring peaks, but oil producers have been bolstered by growth in domestic refining amid higher seasonal fuel demand at home and abroad.

Yet toward the end of the year, any attempt to process more crude domestically and increase output of lighter products — which may find a market in Europe before the February ban is enforced — would also mean production of heavier fuels that are harder to sell in the colder months.

In spring, Russian producers were able to find buyers for their fuel oil in the Middle East after the US imposed its own ban. But demand in that region may ebb as the weather cools, limiting Russia’s ability to export the heavy product, said Mikhail Turukalov, chief executive officer of Moscow-based Commodities Markets Analytics LLC.

In the colder months, Russia also lacks the logistical capability needed for a major hike in fuel-oil exports, Turukalov said.

“This winter, oil-processing in Russia will hardly be able to grow enough to compensate for the expected oil-export declines,” he said.

— With assistance by James Herron, and Julian Lee

أكد الخبير الدولي في مجال الطاقة رودي بارودي أن “لا يزال هناك أخذ وردّ في مسألة ترسيم الحدود البحرية مع إسرائيل، ومصلحة لبنان تكمن في الاتفاق الداخلي واستكمال المفاوضات بموقف موحّد”. واعتبر في حديث  لـ”صوت كل لبنان””93.3″ أن “الموقف اللبناني مرتاح ولدينا مصلحة بأن تنتهي الأمور في أقرب وقت”، لافتاً إلى أن ” الأجواء إيجابية ووصلنا إلى نهاية الشوط لنبدأ مرحلة الاستكشاف”.

Generating power from sunlight bouncing off the ground, working at night, even helping to grow strawberries: solar panel technology is evolving fast as costs plummet for a key segment of the world’s energy transition.
The International Energy Agency says solar will have to scale up significantly this decade to meet the Paris climate target of limiting temperature rises to 1.5 degrees Celsius above pre-industrial levels.
The good news is that costs have fallen dramatically.
In a report on solutions earlier this year, the Intergovernmental Panel on Climate Change said solar unit costs had dropped 85 percent between 2010 and 2019, while wind fell 55%.
“There’s some claim that it’s the cheapest way humans have ever been able to make electricity at scale,” said Gregory Nemet, a professor at the University of Wisconsin-Madison and a lead author on that report.
Experts hope the high fossil fuel prices and fears over energy security caused by Russia’s invasion of Ukraine will accelerate the uptake of renewables.
Momentum gathered pace last Sunday with the ambitious US climate bill, which earmarks $370bn in efforts to cut greenhouse gas emissions by 40% by 2030.
An analysis by experts at Princeton University estimates the bill could see five times the rate of solar additions in 2025 as there were in 2020.
Nemet said solar alone could plausibly make up half of the world’s electricity system by mid-century, although he cautioned against looking for “silver bullets”.
“I think there really is big potential,” he told AFP.

Rapid changes 
The “photovoltaic effect” — the process by which solar cells convert sunlight to electrical energy — was first discovered in 1839 by the French physicist Edmond Becquerel.
After decades of innovations, silicon-based solar cells started to be developed in the United States in the 1950s, with the world’s first solar-powered satellite launched in 1958.
The IPCC said of all energy technologies, small-scale ones like solar and batteries have so far proved quicker to improve and be adopted than bulkier options like nuclear.
Today, almost all of the panels glimmering on rooftops and spreading across vast fields are made in China using silicon semiconductors.
But the technology is changing quickly.
In a recent report, the IEA said these new solar cells have proven to be one-fifth more efficient in converting light to energy than standard modules installed just four or five years ago.
There are also a host of new materials and hybrid cells that experts predict could supercharge efficiency.
These include cheap, efficient and lightweight “thin film” technologies, like those using perovskites that can be printed from inks.
Experts say they raise the prospect of dramatically expanding where solar energy can be harvested — if they can be made durable enough to withstand a couple of decades of use.
Recent research has raised hopes that it could be possible.
In one study, published in the journal Science in April, scientists added metal-containing materials to perovskite cells, making them more stable with efficiency near traditional silicon models.
Other research mixes materials for different purposes.
One study in Nature used “tandem” models, with perovskite semiconductors to absorb near-infrared light on the solar spectrum, while an organic carbon-based material absorbed ultraviolet and visible parts of the light.
And what happens after sunset?
Researchers from Stanford said this year they had produced a solar cell that could harvest energy overnight, using heat leaking from Earth back into space.
“I think that there’s a lot of creativity in this industry,” said Ron Schoff, who heads the Electric Power Research Institute’s Renewable Energy and Fleet Enabling Technologies research.

Location, location 
Generating more energy from each panel will become increasingly crucial as solar power is rolled out at greater scale, raising concerns about land use and harm to ecosystems.
Schoff said one efficiency-boosting design that is becoming more popular for large-scale projects is “bifacial” solar.
These double-sided units absorb energy not just directly from the sun’s rays, but also from light reflected off the ground beneath.
Other solutions involve using the same space for multiple purposes — like semi-transparent solar panels used as a protective roof for strawberry plants or other crops.
India pioneered the use of solar panels over canals a decade ago, reducing evaporation as they generate power.
Scientists in California have said that if the drought-prone US state shaded its canals, it could save around 63bn gallons.
Construction on a pilot project is due to begin this year.

All shapes, sizes 
Experts say solar will be among a mix of energy options, with different technologies more suitable for different places.
Schoff said ultimately those energy grids with more than 25% solar and wind need ways to store energy — with batteries or large-scale facilities using things like pumped water or compressed air.
Consumers can also play their part, said Nemet, by shifting more of their energy use to daytime periods, or even hosting their own solar networks in an Airbnb-style approach.
He said the modular nature of solar means it can be rolled out in developing countries with sparse access to traditional grids.
“You could have solar on something as small as a watch and something as big as the biggest power plants in the world,” he said.
“I think that’s what’s making people excited about it.” — Reuters

The globe is in the grips of a climate crisis as temperatures soar and rivers run dry, and yet it’s never been a better time to make money by digging up coal.

The energy-market shockwaves from Russia’s invasion of Ukraine mean the world is only getting more dependent on the most-polluting fuel. And as demand expands and prices surge to all-time highs, that means blockbuster profits for the biggest coal producers.

Commodities giant Glencore Plc reported core earnings from its coal unit surged almost 900% to $8.9 billion in the first half — more than Starbucks Corp. or Nike Inc. made in an entire year. No. 1 producer Coal India Ltd.’s profit nearly tripled, also to a record, while the Chinese companies that produce more than half the world’s coal saw first-half earnings more than double to a combined $80 billion.

The massive profits are yielding big pay days for investors. But they will make it even harder for the world to kick the habit of burning coal for fuel, as producers work to squeeze out extra tons and boost investment in new mines. If more coal is mined and burned, that would make the likelihood of keeping global warming to less than 1.5 degrees Celsius even more remote.

It’s a remarkable turnaround for an industry that spent years mired in an existential crisis as the world tries to shift to cleaner fuels to slow global warming. Banks have been pledging to end financing, companies divested mines and power plants, and last November world leaders came close to a deal to eventually end its use.

Ironically, those efforts have helped fuel coal producers’ success, as a lack of investment has constrained supply. And demand is higher than ever as Europe tries to wean itself off Russian imports by importing more seaborne coal and liquefied natural gas, leaving less fuel for other nations to fight over. Prices at Australia’s Newcastle port, the Asian benchmark, surged to a record in July.

The impact on profits for the coal miners has been stunning and investors are now cashing in. Glencore’s bumper earnings allowed the company to increase returns to shareholders by another $4.5 billion this year, with the promise of more to come.

Gautam Adani, Asia’s richest person, capitalized on a rush in India to secure import cargoes amid a squeeze on local supply. Revenue generated by his Adani Enterprises Ltd. jumped more than 200% in the three months to June 30, propelled by higher coal prices.

US producers are also reaping bumper profits, and the biggest miners Arch Resources Inc. and Peabody Energy Corp. say demand is so strong at European power plants that some customers are buying the high-quality fuel typically used to make steel to generate electricity instead.

The wild profits threaten to become a political lightning rod as a handful of coal companies cash in while consumers pay the price. Electricity costs in Europe are at record highs and people in developing nations are suffering daily blackouts because their utilities can’t afford to import fuel. Earlier this month, United Nations Secretary-General Antonio Guterres lashed out at energy companies, saying their profits were immoral and calling for windfall taxes.

Coal’s advocates say the fuel remains the best way to provide cheap and reliable baseload power, especially in developing countries. Despite the huge renewable rollout, burning coal remains the world’s favorite way to make power, accounting for 35% of all electricity.

While western producers cash in on the record prices — with companies such as Glencore committed to running mines to closure over the next 30 years — top coal consumers India and China still have growth on the agenda.

The Chinese government has tasked its industry with boosting production capacity by 300 million tons this year, and the nation’s top state-owned producer said it would boost development investment by more than half on the back of record profits.

Coal India is also likely to pour a large chunk of its earnings back into developing new mines, under government pressure to do more to keep pace with demand from power plants and heavy industry.

China and India worked together at a UN conference in Glasgow last year to water down language in a global climate statement to call for a “phase down” of coal use instead of a “phase out.”

At the time, few would have predicted just how expensive the fuel would become. Just a year ago, the biggest international mining companies —  excluding Glencore — were in a full retreat from coal, deciding the paltry returns were not worth the increasing pressure from investors and climate activists.

When Anglo American Plc spun off its coal business and handed it over to existing shareholders, one short seller, Boatman Capital, said the new business was worth nothing. Instead the stock — known as Thungela Resources Ltd. — skyrocketed, gaining more than 1,000% since its June 2021 listing, with first-half earnings per share up about 20-fold.

Glencore itself snapped up a Colombian mine from former partners Anglo and BHP Group. The nature of the deal, and rising coal prices, meant Glencore essentially got the mine for free by the end of last year. In the first six months of this year, it made $2 billion in profit from that one mine, more than double its entire coal businesses earnings in the same period last year.

The earnings look set to keep rolling in, as analysts and coal executives say the market will remain tight.

“As we stand today, we don’t see this energy crisis going going away for some time,” Glencore Chief Executive Officer Gary Nagle said.

— With assistance by David Stringer, and Will Wade