Russia Considers Brent-Based Oil Tax To Limit Its Losses
Russia is considering taxing its oil firms based on the price of Brent – instead of its flagship grade Urals – to limit the fallout on the Russian budget revenues due to the widening discount of Urals to Brent, Russian daily Kommersant reported on Friday, quoting sources. Russia is looking at ways to reduce the steep discount on Urals and to stabilize the oil revenues. At the end of January, Russian President Vladimir Putin ordered the government to submit within a month proposals to change the methodology for calculating the taxes from oil, Kommersant’s sources said. The price of Urals has slumped to a discount of nearly $40 per barrel to the price of Brent Crude, which reduces Russia’s budget revenues from oil export taxes. Since the start of the EU embargo on crude oil imports from Russia and the G7 price cap, the per-barrel crude export duty for the Russian state has shrunk due to the plunge in the price of the Urals grade. Urals crude traded at $49.48 per barrel in January, with rising transportation costs compounding a discount that has seen the country’s flagship crude price plunge year over year. The average price of Urals in January, at $49.48 per barrel, was 1.7 times lower than in January 2022, when it averaged $85.64 per barrel, Russia’s Finance Ministry said earlier this week. The lower the price of Urals is, the lower the export duty on crude and petroleum products is, thus reducing revenues for the Russian budget. So, seeing a threat to the most important budget revenue stream – oil, Russian authorities are now considering amendments in the tax legislation, according to Kommersant. The leading idea is to tie the calculation of the export duty to the price of Brent instead of Urals. The price cap hasn’t impacted materially Russia’s crude oil export volumes, yet, but it has impacted revenues, due to the hefty discount of Urals to Brent. Per Russian finance ministry’s data cited by Kommersant, the tax collected from companies fell by 10% in December compared to November, to $6.75 billion (474.8 billion Russian rubles).
Fitch Expects $95 Oil In 2023
Fitch Solutions has reiterated its oil price forecast for this year at $95 per barrel of Brent crude, citing China’s quicker-than-expected reversal of zero-Covid policies and slow production growth. “On the demand side, prospects for growth have improved, following the earlier-than-expected easing of Covid-19 containment measures in Mainland China,” the ratings agency said, as quoted by The Edge. “On the supply side, uncertainties around Russia continue to cloud the outlook, but slowing production growth in the US, further delays to the Iranian nuclear deal and continued production restraint by OPEC+ will combine to significantly decrease supply growth this year,” Fitch Solutions added. That same set of factors has been cited by other bullish forecasters, too with some of them expecting Brent to top $100 per barrel again this year. Goldman Sachs, for instance, sees Brent hitting $105 per barrel in late 2023 on the back of strong demand growth that would push the oil market into deficit in the second half of the year. Morgan Stanley also sees a tighter oil market in the second half of the year, which could push Brent crude to $110 per barrel by the end of the year. While China’s rebound is already underway and expectations of stronger oil imports have a sound foundation in Beijing’s recently issued import quotas, the situation with Russian oil production is less clear. Many analysts last year expected Western sanctions to affect that dramatically and push oil prices much higher. However, the redirection of exports rather than a production cut ensured a relatively modest impact of the sanctions on global oil supply and, consequently, prices. One other factor that played a part in Fitch’s bullish outlook for oil prices this year was the changed sentiment about the global economy, with expectations now for a milder-than-forecast slowdown. “Despite ongoing headwinds in the form of monetary and fiscal policy tightening, recent data releases suggest that several large economies are holding up better than expected,” the ratings agency said.
India on course to meet green energy targets: Experts
For the second consecutive year, the Union budget announced green measures to ensure India is on course to do its bit in reducing emissions by 2070. This has enthused climate experts. Union finance minister Nirmala Sitharaman’s budget listed green growth as one of the seven priorities of the government and allocated ₹350 billion to achieve clean energy transition and net-zero emissions by 2070. Being the last budget before national elections in 2024 and the upcoming G20 presidency, it has consolidated the government’s position on energy and climate, said Balasubramanian Viswanathan, policy advisor at International Institute for Sustainable Development (IISD), “This is a welcome move as India tries to rapidly increase the share of renewables in the grid. The finance minister also pledged ₹350 billion for net zero and energy transition but an equivalent support of ₹300 billion as capital support for oil-marketing companies and ₹50 billion for strategic petroleum reserves was found. While controlling energy prices and ensuring energy security is critical, India must ensure that financial support is directed towards low carbon technologies.” According to Madhav Pai, interim CEO of World Resources Institute (WRI) India, the inclusion of green growth offers encouragement for the environmental sector. The budget also outlays ₹197 billion for the National Green Hydrogen Mission which, as per experts, must translate into a sharp growth in utility-scale power generation capacities. “Renewable energy constitutes over 50 per cent of the green hydrogen cost and a further decline in clean power costs shall prove beneficial for the emerging green hydrogen economy,” said Martand Shardul, policy director at Global Wind Energy Council (GWEC). On the country’s progress since last year’s budget, environmental experts believe that the government has taken efforts towards its commitments. “The country issued sovereign green bonds, more allocations were made under PLI scheme and also recently under green hydrogen mission. However, on account of Russia Ukraine War, the government’s subsidy burden increased and now it is pushing for increased exploration and production of fossil fuels as well,” said Vibhuti Garg, director, South Asia at Institute for Energy Economics and Financial Analysis (IEEFA). Stating that the budget will lead to significant job creation through the green economy, Vaibhav Chaturvedi, fellow at Council on Energy, Environment and Water (CEEW) said, “Support to various sectors like green hydrogen, bio-manure, offgrid solar and storage among others will create economic opportunities for entrepreneurs. We can expect this to spur the economic development.”
Post-Gazprom, India Turns to US, Mideast LNG Supply
Gail India, India’s biggest distributor of natural gas, is banking on shipments of US LNG, and a new supply contract with a Middle East supplier, to make up for the loss of cargoes from Gazprom. The shift represents yet another impact on worldwide LNG flows in the wake of Russia’s ongoing war in Ukraine. Gail will, for the first time, bring its entire portfolio of US LNG to India this year, company officials said, as it seeks to shore up supplies to Indian customers after Germany’s Securing Energy for Europe (Sefe), which took over a Gazprom subsidiary, failed to deliver cargoes under a long-term gas supply contract. Price sensitive India has slid from being the world’s fourth-largest LNG importer in 2020, at 26.3 million tons, to the seventh largest in 2022, at 20 million tons, amid extremely bullish LNG pricing before and during the war. US, Middle East Supplies A five-year contract to supply 500,000 tons of US LNG to a foreign customer is ending, which will help Gail bring an additional eight cargoes to India this year, director of finance Rakesh Kumar Jain told analysts. The company has two contracts to buy a combined 5.8 million tons per year of LNG from the US, comprising around 90 standard sized cargoes. That includes 3.5 million tons from Cheniere’s Sabine Pass facility and 2.3 million tons from Cove Point. Separately, Gail is in talks with Abu Dhabi, and other Middle Eastern LNG suppliers, including Qatar and Oman, for long term supplies, and expects “to conclude a contract shortly.” It declined to give details, but industry officials expect Gail to secure 1 million -1.5 million tons/yr under the term contract. Additional volumes from the US, and from the proposed Middle East supply contract, will help Gail partly compensate Indian customers for the loss of cargoes under a 2.5 million ton per year, 20-year supply contract from the LNG trading arm of Sefe. Only a third of US volumes will reach India directly, and the rest will be delivered via time and destination swaps. Impact on Gail’s Numbers The Sefe cargo diversion prompted Gail to post a significant inventory loss of 11 billion rupees (about $134 million) in the October-December quarter because it had to scramble to procure spot cargoes at high prices to make up volumes to customers. It paid as much as $45 per million Btu for two cargoes in October but failed to sell it because Indian customers found it unaffordable. Prices slumped to around $20/MMBtu in December, Jain said. By comparison, Gazprom’s cargoes from the Sefe contract are linked at a 13.2% ratio to the Brent crude price, and cost Indian customers $10-$11/MMBtu at current crude levels, industry officials said. Sefe’s failure forced Gail to cut domestic gas sales volumes by around 8.5 million cubic meters a day. Gail reduced supply by 2.7 MMcm/d to fertilizer plants; by another 2.7 MMcm/d to industrial customers as well as cut 3 MMcm/d to the Pata petchem plant, brokerage Nomura said. Gail continues to source 1.5-2 cargoes a quarter on a spot basis, and will need to do so until alternate supplies are secured, the brokerage said in a note.
Will U.S. Shale Ever Return To Its Glory Days?
This article is intended to provide an update on one of the key trends I highlighted in my last OilPrice article on shale output in November. In that article, I discussed signs of maturing of the drilling inventory. Meaning that the number of Top-Tier locations in on the decline, and operators are being forced to drill less productive, lower-tier reservoirs to maintain output. While there is no concern about production from shale reservoirs “falling off a cliff” anytime soon, the fall-off in productivity in at least some basins, is becoming noticeable by a number of metrics. The shale “boom” is about thirteen years old, if you date it from 2010 and there are clear signs the meteoric growth of past years are behind us. Our expectations are for shale production to maintain an upward trend for most of this year, but with an arc that flattens as 2023 waxes on, and then begins to bend down. Perhaps as soon as the end of this year. This opinion flies in the face of generally accepted industry and governmental forecasts that show shale production exceeding 10 mm BOEPD at the end of 2024. Superficially, if you only look at that graph, things look pretty good for production from shale-and other reservoirs on and offshore. But, when you dig down into the weeds, and look past that dotted line that projects future growth, there are some troublesome indicators. We think that 10 mm BOEPD figure is very optimistic and reality will soon set in, resulting in downward revisions to the EIA forecasts. Problems on the horizon with shale output One of the problems with shale production, is the best locations in the various shale basins are well past their prime and shale output could be in the early stages of a death by a thousand cuts. (A death, I remind you again is decades hence, but hanging out there none the less.) This declaration runs in stark contrast to other data taken from the EIA Drilling Productivity Report-DPR, showing shale production is on the increase. How is this possible? A closer look at the table below, taken from the DPR you will see that production is increasing significantly only in one basin-the Bakken, rising incrementally in another-the Permian, and barely staying even in others. What’s up? Interest in Bakken is understandable. Even though it is a mature province, the new well production for Bakken wells is about double that of any other basin at 1,716 BOEPD. This is a known feature of the Bakken and the fact is that horizontal legs are getting longer. The Bakken has increased its rig count by 65% since early 2022, which certainly accounts for much of this increase. More holes in the ground and extending the wellbore account for the increase in that play. The easy answer to increasing production, apart from drilling more holes in the ground, has been to lengthen the interval, and then to up the sand concentration per foot of interval. New research by shale analytics firm, Novi Labs, suggests we may be hitting some practical limits with these techniques. There are limits to the benefits of extending the well bore as discussed in the Novi Labs paper #3723784, The Diminishing Returns of Extending Lateral Length Across Different Basins, presented in the 2022 Unconventional Resources Technology-URTec show. Simply put, the paper, which took a thorough look at a number of U.S. shale plays, concludes that doubling the length of the well doesn’t result in doubling the output. It should be noted that there is a fairly complex discussion in the paper, about possible influencing factors in these results that include, but are not limited to: completion size, a distance of perforations at the toe of the well from the heel, tortuosity, or interactions with artificial lift. Novi Labs has continued its analytical work with a focus on the Midland sub-basin of the larger Permian basin. The graphic below is intriguing in what the data presented might actually mean in terms of long-term shale production. The blue line shows production per foot of interval increasing rapidly to 2016, cresting above 9-bbl per foot cumulative output, and staying in that range in the years since. And, finally, in 2022, dropping back below that level on a fairly steep slope. The orange line shows the average length of the lateral section rising sharply to 8,840’ in 2018, and then flattening out toward 11,070’ in 2022. The dark blue line tracks the average 6-month cumulative production following completion. While continuing to rise, like the other metrics tracked, it flattens post-2016, and by 2022 begins a steep decline. To add to the work done by Novi Labs, is my own work, contained in the graph below, which simply tracks data reported by the Energy Information Agency-EIA, Drilling Performance Report-DPR, on new good productivity through November of last year. I track the new well data from All basins, and the Permian responsible for about half of U.S. daily production, and is cast against data on Drilled but Uncomplete wells-DUCs, and the Rig count for the same time period. I don’t put any interpretation on this data other than to note the decline in new well production over the time span of the data, and to point out the inverse shape of the curve between increasing rigs, and declining DUC withdrawal. Taken together, the data does raise questions about the quality of the shale inventory now being drilled. Takeaways In spite of most data from the various governmental reports showing an increase in production from shale reservoirs, there are observable trends indicating there may be a peak coming, at least on a unit basis. If this trend continues, the only way to maintain output at or above current levels will be with increased drilling. The ability of the drilling contractors to respond to demands for additional rigs is limited by the diminishing stock of idle rigs that meet the “Super-Spec”(walking rigs, higher hook loads, higher standpipe pressures, etc.), or
Fuel subsidies are back: Oil companies to get Rs 300 billion for holding petrol, diesel prices
The Union Budget for 2023-24 will dole out Rs 300 billion to state-owned fuel retailers to make up for the massive losses they ran because of holding petrol and diesel prices despite rise in cost in a bid to help the government contain inflation. Finance Minister Nirmala Sitharaman has allocated the money under the head “capital support to oil marketing companies”. It offered no explanation why the blue chip, cash rich oil PSUs should need capital support. Indian Oil Corporation (IOC), Bharat Petroleum Corporation Ltd (BPCL) and Hindustan Petroleum Corporation Ltd (HPCL) haven’t changed petrol and diesel prices since April 6, 2022, despite input crude oil prices rising from USD 102.97 per barrel that month to USD 116.01 per barrel in June and falling to USD 80.92 per barrel this month. Holding prices when input cost was higher than retail selling prices led to the three firms posting net earnings loss. They posted a combined net loss of Rs 212.0118 billion during April-September despite accounting for Rs 220 billion announced but not paid LPG subsidy for past two years. That freeze had led to record high losses of Rs 17.4 per litre on petrol and Rs 27.7 a litre diesel for the week ended June 24, 2022. However subsequent softening led to losses on petrol being eliminated and diesel coming down to Rs 10-11 a litre. Retail rates havent been changed when oil prices well to help the oil companies recoup the massive Rs 500 billion under-recovery they ran for holding prices.