Note: This blog is the third and final in a series addressing key developments affecting the energy industry. In the first, we explained the five reasons oil prices fell despite supply risks. In the second installment, we detailed how developments in Europe were set to impact global markets.
As we work through the final days of November, global oil prices are continuing their slide lower while natural gas prices are once again pushing higher. We are now just a few days away from the start of the EU’s long-awaited December 5 Russian waterborne crude import embargo and the G7’s Russian oil price cap scheme. While the deadline has been known for months, policy makers from EU and G7 nations are only now working to come to final agreement on key details—like the price level of the cap itself—and issuing guidance in the final days of November. In the early days of March, following Russia’s invasion of Ukraine, we outlined how past energy policy decisions in Europe severely limited sanctions options for Western allies and why—given vastly different levels of dependency on Russian energy across Europe and to avoid an immediate economic catastrophe—this meant Russian oil and gas would likely continue to flow to global markets.
In the first of this three-part blog series in September, we outlined why oil prices moved steadily lower through the summer despite numerous bullish tail risks. Key to that price decline was a market that was not only seeing more Russian oil hit the water than was initially anticipated, but also increasingly realizing Western nations and their allies were growing more concerned with limiting domestic inflation than limiting Russian oil revenues. As we detailed in last month’s edition of the blog series, developments in recent months only further corroborated our view that the position of G7 and EU allies was softening as the December deadline approached. Given the need to appease everyone in a party with vastly different economies and levels of dependency on Russian energy, the EU is now at serious risk of not achieving their initial goal of slashing Russian oil revenues by potentially approving a price cap above the current market price. Recent insight into the final details of the policy measures only further strengthens our view that oil prices are likely to continue to face headwinds moving into 2023 while natural gas prices (particularly in Europe) are set to remain stubbornly high.
Here are our five key factors set to drive oil and gas prices as we move into 2023:
1. The Fallout from Price Caps and Embargos on Russian Oil
Less than a month before the EU embargo on Russian crude oil imports and accompanying maritime services and insurance ban are bound to come into effect, the continent’s refiners are still relying on a steady stream of Urals crude. At 800,000 bpd, waterborne crude oil flows from Russia to Europe still clocked in at around half the pre-war pace last month. Since the invasion, Russian crude oil continued to flow to Europe via the 1.4 million bpd capacity Druzhba pipeline system, albeit at a reduced rate. Hungary, Slovakia and the Czech Republic, who lobbied for their main source of crude oil to be exempt from EU sanctions earlier this year, have in recent months imported around 250,000 bpd via the southern arm of the pipeline. Deliveries to Germany and Poland on the larger northern section of the pipeline ran at around twice that rate over the same time, markedly below the pre-war pace of approximately 650,000 bpd.
The German and Polish government first signaled in May intentions to end receipts from Druzhba starting January 1 and have since been working on sourcing alternative crude supplies for the refineries which overwhelmingly depend on the Russian pipeline system. However, there isn’t yet sufficient infrastructure in place to fully replace this stream. The Schwedt refinery in particular (which accounts for about a tenth of German fuel production) is not only finetuned to refine Urals crude but also has limited options to draw crude from elsewhere. A crude pipeline from the port of Rostock connected to Schwedt would only allow the refinery to run at less than half capacity. Cooperation between regional refiners and the German and Polish governments as well as a swift buildout of infrastructure would allow the continuation of operations at slightly reduced rates, as refiners could coordinate on piped deliveries and allow for additional supplies to come in via the Polish port of Gdansk. German chancellor Scholz last week reiterated plans for refineries in Schwedt and Leuna to be able to operate without Druzhba starting January 1, calling supply negotiations with Poland “well advanced.” Given the current rate of Russian oil imports, European refiners will have to source some 800,000 bpd from elsewhere come December and an additional 600,000 to 700,000 bpd come January.
European Ports for Russian Oil Landings
On the flip side, Russia will have to find new buyers for these volumes or be forced to curb production. While the steep discount on Urals crude continues to attract buyers, it is doubtful that India, China and other countries who have stepped up their purchases of Russian crude oil since the invasion can or are willing to make up the entirety of the difference. EU- and UK-based shipping and insurance services being off limits unless sold under the price cap come December poses a serious challenge to Russia, which does not possess a tanker fleet capable of replacing European-insured ships. As impactful to the global supply demand balance the EU’s decision on adopting or not adopting the G7 plan could be, much will ultimately depend on Russia’s handling of the price cap.
The Kremlin has naturally rejected the western dictate from the get-go and ruled out any compliance. Russian Energy Minister Novak just recently reiterated that Russia will not sell crude oil and oil products at any price cap and might consequently halt some crude production. While the Kremlin’s publicly communicated refusal to adhere to the cap has not inspired confidence in third country purchasers, some of whom will also look for alternative crude supplies, the G7’s proposed price cap range of $60-$70/bbl is now giving the Kremlin little to worry about. In fact, with a price cap now eyed above the market price, the price cap is ineffectual for Russian Urals crude and will only mean more paperwork for shippers to nations outside the EU.
Urals North Crude vs. Brent CFD
The relatively poor quality of Russian Urals, the extremely expensive and lengthy shipment of Urals outside of Northwest Europe, and a limited number of buyers already have Russia’s flagship crude grade trading at a $25/bbl discount to Brent, or $60/bbl. For Russian ESPO crude, however, the price cap situation will be a bit more precarious. While the primary price cap enforcement risk lies with ESPO loadings, given the highly sought-after grade trading well above the suggested price cap range and their largest buyer in China in close proximity to the point of loading, it is likely that many of these cargoes will find shippers outside of the European framework. Russia may be betting on this year’s Asian buying frenzy of Urals to continue unabashed, but our global economic outlook is less than conducive to firm oil demand growth in 2023.
Russian crude oil loadings have picked up pace in recent weeks ahead of the December 5 embargo. As was the case with prior instances of sanctioned and embargoed oil sales, loadings on vessels without a declared destination have reached record levels, suggesting a rush to get as much crude as possible on the water before the December deadline. According to guidance issued by the U.S. Treasury, any barrels loaded prior to December 5 will not be subject to the price cap as long as the cargo is unloaded before January 19. Including undeclared vessels, waterborne crude exports from Russia destined for China, India and Turkey reached a record 2.45 million bpd in the four weeks to November 18, according to vessel tracking data from Bloomberg, while flows to Northwest Europe, formerly the largest buyer of Russian oil, dipped under 100,000 bpd.
EU-27 Waterborne Imports of Russian Crude Oil
Given the multitude of factors at play, the impact on Russian crude output can range from a few hundred thousand bpd to millions of bpd of shut-in production. The IEA in its latest monthly Oil Market Report once again cut its expectation for supply losses as a result of the looming sanctions package and price cap. In November, the single largest change in the IEA’s monthly oil outlook was another large upward revision to Russian oil supply expectations. The IEA sees an increasingly subdued price cap and embargo effect, revising January 2023 Russian production expectations to 10.5 million bpd, some 500,000 bpd higher than the agency’s October estimate.
In addition to pipeline carve-outs, some European countries early on received waterborne import exemptions for Russian crude oil (Bulgaria) and VGO (Croatia). As we described in part 2 of this series, sanction proposals have softened continuously over the past nine months as policymakers were confronted with harsh economic realities. The EU recently proposed pulling the teeth from one of the few remaining biting punishments by limiting penalties for vessels caught carrying Russian crude oil above the price cap to 90 days instead of the originally proposed indefinite sanction. Italy may lobby for a last-minute embargo waiver to keep Lukoil’s ISAB refinery in Sicily operational with plans to nationalize the refinery, and Japan recently received a concession from the G7 that imports from Sakhalin-2 will not fall under the price cap regime. Inflationary pressure, as well as pushback from Cyprus, Greece and Malta (key shipping nations), looks set to push the EU to abandon a complete ban of maritime and insurance services for the transportation of Russian oil in favor of adopting the G7 price cap plan, the legal framework for which was adopted in the eighth sanctions package on October 6.
Crude Prices Relative to Suggested Price Cap Range
With the proposed fixed price cap now at or even above current market rates for Russian Urals, the effect on Russian state revenues will be more than manageable, while Europe will pay higher prices for imported fuel, and refining margins on the continent suffer. At the end of the day, EU and G7 policies regarding Russian energy commodities may do more to hurt the European refining sector than the Kremlin’s war chest, all to the benefit of U.S. and Mideast refiners who have much lower production costs and Asian refiners who continue to benefit from cheap Russian barrels.
Well ahead of the EU’s embargo on Russian oil product imports scheduled for February 5, the continent has been and is continuing to face a tight diesel market as slowing Russian crude oil, feedstock and diesel flows, lost refining capacity, high natural gas prices and unplanned refinery outages in the midst of fall maintenance season have left low sulfur diesel in short supply. While Europe will have to pay a higher price for diesel imports from the U.S., the Middle East and Asia—a portion of which will ironically be refined from Urals crude—with European industrial and economic activity in sharp contraction, global trade slowing markedly and the European economy skidding into recession, slowing diesel demand should continue to help buffer supply side risks.
2. Winter Weather
Autumn and early winter weather has been extremely merciful to those hoping to see lower energy prices and few industry disruptions. The western U.S. Gulf Coast region, home to the majority of U.S. oil refining, production and export capacity, nearly completely avoided disruption this hurricane season. On the other side of the pond, the six largest economies across Europe all saw above-average temperatures in October, allowing for brimming natural gas inventories and plummeting prices. Even so, with extremely narrow heating oil inventories in key consuming regions, natural gas flows from Russia to Europe cut by over 80%, high natural gas prices causing gas-to-oil switching, and France having continued issues with their nuclear generation fleet, weather developments are going to be more important than ever for energy markets this winter.
To understand why winter weather is so important for energy markets, one need only consider the massive role fossil fuels play in heat and electricity generation. In the EU, natural gas accounts for a third of total energy consumption by households, with another 24.8% coming from electricity. Natural gas-fired electricity generation accounts for around 22% of EU electricity generation, and for EU households heating their homes makes up over 62% of their energy consumption. The average retail natural gas price across the EU and UK was nearly $0.18/kwh in October, doubling from the same month last year when prices were already on the rise. Residential electricity rates are up over 65% year-on-year to around $0.36/kwh.
In the U.S., natural gas provides the energy source for nearly 40% of total electricity generation, and electricity is used by around a third of Americans to heat their homes in winter. Furthermore, natural gas is relied upon by nearly half of Americans to heat their homes for direct use in home furnaces, boilers, and other gas-fueled heating equipment. Amid winter temperatures, combined residential and commercial direct consumption of natural gas typically jumps to levels 4-5 times those seen during the summer. The most recent surveys of energy use in the residential and commercial sectors by the EIA showed natural gas accounted for 68% of heating consumption in homes in 2015. Winter heating season looks set to continue to strain household budgets, with the EIA’s base case forecast calling for U.S. average household expenditures for heating with natural gas rising 28% year-on-year.
EIA Base Case Forecast
Given this reliance on natural gas as a winter heating fuel and a growing share of natural gas in the electricity generation mix, it’s easy to see why winter weather developments are so crucial for the natural gas price outlook. To further contextualize this point: in the EIA’s Winter Fuels Outlook, a 10% colder-than-forecast weather scenario developing this winter would lead U.S. natural gas inventories to end March 2023 41% below the five-year average at around just 0.9 Tcf. Natural gas prices would be 5% higher than their current base case and consumption would be 13% higher. However, in a 10% warmer-than-forecast scenario, natural gas inventories end the winter 18% above the five-year average at nearly 1.8 Tcf. In this instance, gas consumption would be 5% less than the base case and prices would be 2% less than currently forecast.
End-of-Month U.S. Working Natural Gas in Storage, 2020–2023
Amid exorbitant natural gas prices in both Europe and the Northeast U.S., households and industries in these regions are economically compelled to switch to oil-fired heat and power generation where possible. This will be increasingly important for electricity generators in the U.S. Northeast who have limited domestic natural gas pipeline capacity and have to increasingly compete with Europe for LNG cargoes. On a barrel of oil- or btu-equivalent basis, European and Asian LNG prices are five times as expensive as high sulfur fuel oil. While the high sulfur fuel oil market is well supplied, tightness in low sulfur diesel, heating oil and fuel oil markets that have led to record-strong refining cracks for diesel in recent months in part already reflect fuel switching economics over the past year. In total, heavy industries like oil refining and power generation are estimated to help drive gas-to-oil switching to account for 500,000-700,000 bpd of incremental oil demand this winter.
DTN U.S. Seasonal Forecast, December 2022–February 2023
Weather forecasts for the U.S. and Europe have turned increasingly cold for the month of December in recent days, spurring on natural gas and electricity prices. For the U.S., the DTN 31-90 day seasonal forecast currently calls for below normal temperatures in the Coastal Northwest, Central-Northern Rockies, Central-Northern Plains and Midwest. Meanwhile, our meteorology team expects above normal temperatures in the Southeast and seasonally normal temperatures in the Northeast. On balance, this leads DTN to expect November-March gas weighted heating degree days (HDDs) to end the winter at their highest since the winter of 2019 and 4.5% above year-ago levels.
DTN EU Seasonal Forecast, December 2022–February 2023
In Europe, DTN expects winter temperatures to average above normal in the southern half of the continent, particularly the Mediterranean coast. However, below-normal temps are expected in the UK and northern Europe. Furthermore, below normal wind anomalies (which the UK is currently suffering from) are expected in the UK and northern Europe this winter. While our January forecast calls for milder and wetter conditions across Europe, below normal temperatures in February are a risk for Scandinavia, France and the Iberian Peninsula.
3. A Weakening Global Economy:
We continue to believe it is highly unlikely that the Federal Reserve can guide the U.S. economy to a soft landing following the highest inflation and interest rates in decades. The European economy is currently sliding into recession, Chinese growth will not be what it once was for the foreseeable future, and the U.S. looks set to move into a recession in late Q1 according to leading economic indicators. The list of economic and financial statistics that lead to a conclusion of “this has never happened without a following recession” is now too long to list. Meanwhile, real U.S. Q3 GDP moved back into positive territory after two consecutive quarters of year-on-year contraction and the Atlanta Fed’s GDPNow tracker for Q4 is expecting a positive print once more. However, we continue to believe—particularly for the sake of oil and gas demand outlooks—the devil is in the economic details.
As we detailed in September, gasoline and diesel demand in both China and the U.S. have severely disappointed expectations this year. The EIA’s gasoline demand proxy, which last year showed gasoline demand above 2019 levels for the current seasonal period, currently shows gasoline demand around 650,000 bpd below year-ago and 2019 levels using the 4-week moving average measure. So far in the second half of 2022, gasoline demand is averaging 632,000 bpd below 2021 levels for the period and demand is averaging 617,000 bpd below 2019 levels so far this year using the same 4-week average measure. Given that gasoline demand has remained relatively weak even as retail prices have declined, we continue to believe a combination of income elasticity amid multi-decade-high widespread inflation and the lasting impact of COVID-19 (e.g., the rise in work from home) is limiting demand. With gasoline demand already weak and set to continue to follow a seasonal weakening pattern for the next few months, this will make diesel demand and margins even more important for refiners moving into 2023.
EIA Gasoline Product Supplied
The EIA’s 4-week average demand proxy for distillate fuel oil averaged 206,000 bpd below year-ago levels from April through mid-September amid slowing diesel-intensive economic activity. By mid-September, the EIA’s demand proxy showed distillate fuel oil supplied continuing its weakening trend and sliding to a 600,000-bpd deficit to year-ago levels. This fell in line with the weakening trends we were witnessing and expecting in both over-the-road and waterborne freight markets. The Institute for Supply Management (ISM) manufacturing PMI fell to 50.2 in October from 50.8 in September, both the lowest readings since May 2020 for the index. New Orders as measured by the ISM fell for the second consecutive month in October. However, the EIA’s measure for distillate fuel oil demand rocketed 800,000 bpd higher between early September and early October. DTN Refined Fuels Demand data show that this surge in the EIA’s measure of distillate fuel oil product supplied over the period primarily reflects a surge in heating oil demand rather than on-road diesel demand.
EIA Distillate Fuel Oil Product Supplied
Similarly to how gasoline panic-buying briefly caused a surge of gasoline demand earlier this year, with headlines of potential heating oil shortages and inventories in the northeast U.S. at critically low levels, it appears that fuel retailers, households and businesses spared no expense to fill their tanks well ahead of their usual winter schedule. This pulled heating oil demand that would not normally be seen until late October forward into late September. This pulling forward of seasonal demand points to U.S. distillate fuel oil demand having already peaked for the fourth quarter, which should be a worrisome sign for those positioned long oil or diesel, given that the 4-week average for distillate fuel oil product supplied is already below 2020 levels and nearly 400,000 bpd below 2019 levels for the seasonal period as of the week ending November 13.
WCI Shanghai to LA Container Freight Benchmark Rate
Economic weakness, and particularly the bullwhip effect that we previously described plaguing U.S. goods retailers and the global freight industry, looks to be in the process of retaking the dominant role in global middle distillate markets following refinery strikes in Europe, as well as the temporary U.S. heating oil demand surge. Ocean container freight rates from China to the U.S. West Coast have now collapsed over 90% from their peak, as container traffic at southern California ports has collapsed to levels last seen in early 2020. This container freight rate and volume collapse is entirely consistent with an economy moving into recession. Furthermore, after already weakening for the past six months, FreightWaves data show the U.S. trucking market experiencing a sharp deceleration moving into November as retailers are well supplied and have no need to replenish inventories ahead of the holiday season.
Outbound Tender Volume Index, USA
The S&P Flash U.S. Manufacturing PMI is signaling manufacturing plunged into contraction this month, falling to 47.6 in November from 50.4 in October. Furthermore, their early read of the services PMI fell to 46.1 in November from 47.8 in October, bringing the composite PMI into further contraction at 46.3. The lagged impact of the Fed’s monetary tightening following years of largess will combine with a slowing global credit impulse to increasingly dim the outlook for global growth as we work through late Q1 and into Q2 2023. The U.S. Conference Board Leading Indicator Index, which incorporates 10 different leading economic indicators, has a 50-year track record of anticipating recessions and the indicator is flashing recession as we move into 2023.
US Conference Board Leading Indicator Index
This leads us to conclude that we are likely to see continued builds to U.S. distillate fuel oil and gasoline inventories, as well as rising volumes of U.S. refined product supply being pushed to the global market, in the coming months. That said, diesel inventories are likely to be slower to build than would otherwise be expected amid the slowdown in global economic activity. A large premium for diesel relative to gasoline is set to remain amid the influence of winter weather, the EU Russian refined product embargo hitting in February and IMO bunker fuel regulations which have helped limit low sulfur fuel availably since early 2020. While this means it will likely take longer than usual for slowing refined fuel demand to translate into lower crude demand at refiners, it also means that gasoline inventories could swell rapidly this winter.
4. China’s COVID-19 Policy
For many investors, the potential of an end to China’s “Zero-COVID” policy approach has been a hoped-for yet not-realized bullish catalyst for global equity valuations, global trade, commodity demand and oil prices for well over a year now. As we detailed in the first blog of this series, China’s persistence of Zero-COVID enforcement was key to lower global oil prices this year. Therefore, a potential turn in this policy remains a bullish risk for markets looking toward 2023. For those following Chinese politics, October’s 20th Communist Party Congress was long thought to be that turning point in China’s Zero-COVID policy. Concerns over Chinese President Xi Jinping using the party congress to maximize his control over the Chinese Communist Party proved well founded, and long-rumored changes to China’s COVID policies did begin to materialize in the days following the codification of Xi’s dominance. However, just days later, the government’s response to record high COVID cases in November continued to point to a slow and painful normalization process lying ahead.
In early November, Chinese officials announced that China would begin to ease COVID restrictions, vowing to maintain COVID protocols while minimizing economic and social disruptions. This process started with changes for inbound international travelers. But as details emerged, it became clear that this was still an extremely restrictive policy. International travelers who do not live in China will still need to spend eight days in quarantine upon arrival. Inbound international passengers will see their pre-departure test requirement reduced from two negative tests to one and mandatory centralized quarantine upon arrival cut to five days from seven, followed by another three days of home isolation. While this may buy another 100,000-200,000 bpd of jet fuel demand in the coming months, it certainly will not inspire a return to anything near pre-COVID Chinese air travel.
Russian Waterborne Crude Exports by Destination
Did the communications following the Party Congress signal the beginning of the end for China’s Zero-COVID policy? No one can truly say, but the events that have unfolded over the past month following the much-hyped easing of COVID directives are a stark warning to those eager to bet on a rapid turn in Chinese COVID policy. Just days after headlines told of easing restrictions, outbreaks in some of the nation’s largest cities led China’s top health officials to stick with their approach of mass testing, shutting people in their homes and businesses, and severely limiting travel. Although it does appear the average severity of COVID-related restrictions have eased in recent weeks in China, the nation’s largest cities are actually stepping up enforcement as cases rise.
While it may be a more gradual approach than what was seen in months past, millions of people across China remain unable to partake in economic or social activity. Think of it as a growing web of restrictions rather than a blanket, city-wide lockdown. According to Nomura Holdings, residents in 48 Chinese cities are currently subject to some sort of movement restrictions. With increasing COVID cases causing the largest Chinese cities to step up restrictions, more oil demand than ever is currently at risk from Chinese COVID-related restrictions.
Given that we know COVID-19 is an endemic disease that will be with us indefinitely at this point, and with China still months away from the prospect of even a potential widespread vaccination campaign among the elderly, it seems unlikely that the Chinese economy and domestic refined product demand will get back to pre-COVID levels anytime soon. While Beijing is continuing to signal change is coming regarding its Zero-COVID policies, ongoing nationwide protests in recent days against such measures are likely to delay a reopening in the near-term. This means Chinese crude oil demand will remain highly dependent on global refined product demand and government-granted refined product export quotas as we move into Q1 2023. While Chinese refiners are currently in the process of responding to the extremely large refined-product export quota allotted by the government in October, and their jumping into the spot market for deliveries in December and January helped support crude prices in October, this impact was short-lived. The Asian diesel market has been softening since October, and with the prospect of continued export strength from China moving into the new year amid a backdrop of a slowing global economy, this is likely to further weigh on refining margins and crude demand in the region moving through early 2023.
JKM LNG – Dutch TTF $/MMBtu
Reduced economic activity over the past year allowed for rising volumes of Chinese LNG being re-sold into the LNG spot market amid record-high European natural gas prices earlier this year. In October, China’s National Development and Reform Commission asked state-owned gas importers to stop reselling LNG to secure volumes for domestic use this winter. A combination of falling European natural gas prices amid brimming storage and rising Asian demand led the JKM LNG discount to Dutch TTF to narrow from more than $25/MMBtu this summer to just $8.80/MMBtu. Even amid sharply reduced economic activity in China, it’s important to consider that JKM LNG is still trading at a $24/MMBtu premium to Henry Hub, incentivizing U.S. exports. For reference, at this time in 2019, JKM’s premium to Henry Hub was just $3.10/MMBtu. Therefore, Chinese reopening is not only a bullish risk for oil but could further pressure global natural gas prices.
5. OPEC Decisions
The risk of production cuts by OPEC has loomed over global oil markets throughout the second half of the year. Saudi Arabia earlier this year seemed to be perfectly positioned to take advantage of the loss of Russian crude output come December. As one of the few oil producers with notable spare capacity, it could even step in for some lost barrels while keeping prices within their desired range. A globally tight low-sulfur middle distillate market outlined in our previous blog, combined with inflationary pressures and global quasi-recessionary developments, however, greatly diminished their potential to capitalize on the moment.
High natural gas and shipping costs have eaten away at refining margins for sulfur-rich Saudi crude oil. The quality mismatch has made sweeter grades like Russian ESPO much more desirable, which considerably soured the Kingdom’s outlook. Even Emirati crude, which is already trading at the highest discount to Brent since June, seems to be a better fit for Asian refiners than Arab Light. Singapore refining margins for the latter are currently some $4/bbl below Dubai/Oman and $14/bbl below ESPO. Ironically, the player who seemingly had the most to gain from Russian oil being off the market is losing out to Russian ESPO.
Brent Dubai November 2022
After a partly politically motivated 2 million bpd production cut announcement, 900,000 bpd of which have been realized, in late November rumors spread that OPEC+ is considering upping output. While delegates from multiple countries were quick to deny such stories, the group is staring down the prospects of a global recession at a time when Russian oil will continue to flow in substantial amounts. Signs of demand weakness have already appeared after the buying frenzy of recent months, as unsold cargoes have started to amass on West African and Russian waters in near-record amounts. Curbing OPEC production further to support prices may turn out to be a losing battle for the group, particularly for the Saudis, who would bear the brunt of the burden of further cuts. To make matters worse, other major producers in the group, notably Iraq, will be less than inclined to support and in practice execute deeper cuts. Given this backdrop, market share concerns could once again gain in importance, meaning OPEC+ decisions carry both bullish and bearish risks for oil prices moving into 2023.
With no EU agreement on the G7 price cap deal and the December 5 deadline only days away, the risk of a political failure leading to volatility in the coming days cannot be overlooked. However, we continue to believe that negotiations will likely deliver a price cap that can spare the worst-feared impact of the EU’s maritime services and insurance ban. Furthermore, with a growing tanker fleet preparing to operate outside of the Western framework and little penalty for those caught doing so, the bullish risk of the December 5 deadline is smaller than it once was–whether an agreement is reached or not. Combine this with a backdrop of slowing global economic activity and the Biden Administration may have their opportunity to provide some stability and support to prices by buying barrels to refill the SPR in the coming months. That said, we doubt that OPEC+ (of which Russia is a key party), will care for this prospect, creating the potential for turmoil within the group in the coming months.
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About the Authors
Troy Vincent is a senior energy market analyst at DTN. He worked at the Charles Koch Institute and studied at the Mises Institute while completing his Bachelor of Science in business economics and public policy from Indiana University and has been in the economic research and energy risk management industry for the past decade. Throughout that period, he has served as an analyst covering electricity, carbon dioxide, coal, natural gas, crude oil, and refined products markets. After advising companies on their energy risk management strategies while at Schneider Electric and Trane, Vincent served as a senior oil market analyst for innovative technology startup ClipperData, providing actionable intelligence for oil traders and investors. He currently specializes in crude oil, natural gas, and refined products markets; you can find his past comments and analysis across industry reports from RBN to Barron’s, MarketWatch, and Bloomberg.
Karim Bastati is a market analyst at DTN. Bastati has nearly a decade of experience in data analysis, spending the last few years in the energy industry interpreting data and building predictive models. He often acts as the central link between quantitative and qualitative research, joining an extensive knowledge of global oil markets with an analytical, numbers-oriented approach. In his previous position at ClipperData, he authored several weekly reports on crude oil and petroleum products, delivering data-derived insights.