Loss of Russian Crude and Product Exports
The uncertainty around forward Russian oil supplies helped drive WTI to its highest level in eleven years this week. On Thursday, April WTI traded as high as $116.57/barrel and prices were consolidating above $110 on Friday.
Russia has struggled to locate buyers for its benchmark Urals crude this month even without official sanctions on energy, still under consideration by the Biden administration. Nonetheless, the shipping, insurance and banking industries are refusing to provide vessels, insurance, and the Letters of Credit required to purchase and load waterborne cargoes, a de facto commercial embargo.
De Facto Commercial Embargo
As a result, about 2.5 million bpd of crude supply is now at risk in a global market that was already in material deficit. This takes on even more gravitas given the Saudi/OPEC inclination to maintain the status quo on supply increases. Likewise, growing tension/strife in Libya this week is now putting their production and exports at risk.
About 2 million bpd of the above 2.5 million bpd is short-haul Urals Blend exported via the Black Sea and Baltics to buyers in the Mediterranean and NW Europe. The remaining 500,000 bpd is ESPO Blend exported to Pacific markets via Kozmino.
The impediments to buying and shipping Russian crude have created a dramatically two-tiered market for both prompt physical barrels and freight rates. On Friday AM prompt “Dated” or physical Brent cargos were trading around $5.00/barrel premium to prompt (May) Brent futures. Shell reportedly today purchased a prompt Urals cargo today at $28.50/barrel discount to Dated Brent. This compares to a pre-invasion average for Jan 2022 at Dated Brent less $1.35 and the average for Cal 2021 at -$1.37.
Atlantic Basin Product Supply Impacted as Well
Russia rivals the US for the role of largest global exporter of refined products. On top of the 2.5 million bpd in crude exports, Russian exports another 1.5 -2.0 million bpd of products. This is mostly distillate sales to Europe, which is dependent on diesel supplies from the US and Russia to balance demand.
While some like Shell were willing to “pick off” a single deeply discount Russian Urals cargo this week the real litmus test will come on Saturday. That is when Rosneft’s tender for 83 million barrels of April-October term crude sales closes. It should provide an excellent indication of the longer-term appetite to purchase Russian crude under murky circumstances.
Global Natural Gas Market Implications from Russia/Ukraine Conflict
While Crude and Crude Product markets have soared and garnered many of the headlines as it relates to the Russia/Ukraine conflict it is the global gas market which could experience some of the most lasting impacts from this geo-political event. Although political and social narratives around the world continue to be concentrated on drastically reducing or altogether removing fossil fuels from the power sector, in the near term economic stability and industrial production will remain reliant on natural gas.
The Northern European natural gas market has already experienced its share of remarkable volatility, and this comes as no surprise since the European continent relies on the Russian supply of natural gas for its heating and power needs. Forward TTF prices have doubled at the front of the curve in the past week. April TTF futures are trading over $60/MMBtu, and the remainder of the summer (Apr-Oct) strip is comfortably over $50/MMBtu, except for the October ’22 contract which is just under at $49.64. As a reflection of the dire situation for late winter heating needs and summer refill requirements, the October ’22 TTF contract is trading at a remarkable $10/MMBtu premium to Jan ’23.
One of the first takeaways we see from the Russia/Ukraine conflict as it pertains to natural gas, and for that matter, crude products, is the possible redistribution of supply and the costs of said supply since there have yet to be reports of actual production impacts. While the Western World increasingly walks away from all ties to Russian energy in the above noted de facto commercial embargo, China, several Eastern European countries, Iran, and likely other Middle Eastern nations could benefit from being buyers of Russian energy supplies in a far less competitive market. How this impacts global industrial production and power markets will be an interesting topic to follow in the coming weeks/months.
Attempts to cripple Russia through sanctions, both direct and indirect, on all facets of their energy-focused economy can and will have inflationary implications for Western nations. One immediately apparent impact is seen in global coal markets, which can at times go overlooked since coal has been out of favor for several years. Front-month coal prices from Australia, to South Africa, to Northern Europe, and beyond have doubled in the past 5 days. For reference, a rough approximation places current global markets at near $20/MMBtu. Global coal markets have ascended to record highs just like European natural gas. Consider what this will mean for countries that are steadfast in their requirements for emissions credits and the like. Emissions markets have also continued to remain on an upward trajectory since the widespread announcement of net-zero goals late last year. Record high coal plus pricey emissions credits will ultimately be costs passed on to the consumer. Some relief seems to be showing up in emissions markets with the front-month EUA contract having collapsed from more than $90/MT to just under $65/MT. Whether this is a sign that emissions requirement could ease is yet to be seen, and $65/MT is still a costly tax relative to where these same credits were trading a year ago ($40/MT).
Domestically natural gas markets have begun to respond to what in our view has been a clear-cut BTU crisis since last fall. However, the rally in NYMEX futures pales in comparison to European natural gas, European power, and global coal. With the summer injection season flirting with $5.00/MMBtu consumers in North America are certainly taking notice, yet the crunch on margins for industrial consumers and the impact on household budgets is more a coming event than a present reality.
Since Europe is pricing to bring all available LNG cargos to its shores from any location it is produced, it’s logical that U.S. LNG exports will remain maxed out for the foreseeable future. The limitations to U.S. LNG exports will be maintenance-related outages or weather-driven curtailments. This is a bullish tailwind for domestic natural gas markets, but one which must be understood in that any incremental supply will have to be absorbed domestically. It does not matter if a magic wand is waved and North American production surprisingly finds a renewed double-digit growth trend. There is only so much that can be exported. Theoretically, a production increase into a maxed out LNG export environment would be a headwind for domestic natural gas prices but remember the investing public, industrial consumers, and households have yet to live through an energy pricing environment akin to what has impacted Europe for more than 5 months now. Not to mention the fact that industrial demand could rise substantially in North America since the cost of producing a unit of almost anything is cheaper in our current energy pricing environment relative to the rest of the world.
Fast forward to mid-summer and/or next winter, and ponder what could become of North American energy markets if we have elevated temps in the Southern U.S. (mid-summer) and power demand climbs to a level that requires competition to keep more MMBtus at home, or next winter if another Feb ’21 like cold event blankets the lower 48. For all North American consumers of natural gas or power, there are material risks that assumed energy budgets could be blown through with ease.
Producers and end-users of energy alike should brace themselves for what is likely to be a very interesting summer and winter ahead. For North American producers the focus on existing derivative books, unhedged positions, and credit capacity should be front and center. Dynamically using all resources available will likely be required this year more than most. For consumers of North American energy, the elevated pricing environment experienced since the Fall should be considered a warning shot. Realized costs may very well get worse before they get better. Understanding the relationship between natural gas prices and power markets, in a world without a ‘cheap’ fuel switching alternative, is imperative.
Paradoxically we find ourselves in a world where Western powers are politically rallying around reducing reliance on fossil fuels, having insufficient stockpiles of stored BTUs for the near term, and at the same time feeling compelled to cut off access to one of the world’s larger energy producers. Strange times to say the least. Adding a fun fact to the less than fun world where BTUs are scarce, is the fact that the last time there was a large-scale Eastern European conflict there was also a Major League Baseball (MLB) players strike (Bosnian War and 1994 MLB strike). For the sake of energy consumers and fans of MLB, may reconciliation of conflict be sooner rather than later.
John Saucer
Prior to joining Mobius Risk Group as Vice President of Research and Analysis, John spent 13 years at the Houston based energy fund AAA Capital Management Advisors as a Trading Principal and Petroleum Specialist. Previously, he was a Vice President of Commodity Futures Sales at Citigroup. During his 12‐year career at Citigroup, he also spent 7 years as a Vice President of Energy Analysis, responsible for fundamental research in the firm’s Futures Research Department. Prior to his work at Citigroup, John spent 5 years as a senior editor at Petroleum Argus, a leading international oil market publication. John is a graduate of The University of Texas with a BA in Economics.
Zane Curry
Zane has been with Mobius Risk Group since February of 2016. His primary responsibility is a fundamental analysis of the North American natural gas market. Additionally, he assists in the valuation of gathering, processing, transportation, and physical sales agreements. His experience in energy has been focused on natural gas, however, as the North American hydrocarbon value chain has become a more integrated system his knowledge has expanded to crude oil, petroleum products, and seaborne LNG. Prior to joining Mobius, Zane spent 6.5 years with a Houston based hedge fund (Goldfinch Capital) with AUM of approximately $750M. In his time with Goldfinch Capital, Zane was tasked with developing detailed models of the North American natural gas market, including 1st derivative components such as power generation by fuel source, supply side impacts of liquids focused drilling, etc. Zane is a graduate of Rice University, and a former member of his alma mater’s baseball program as both a player and coach.