For oil, we quantified the RRP at a historically unprecedented mark of around $10-$15 per barrel. We make this estimate by analyzing the statistical relationship between OECD inventory levels and changes against the shape and position of the Brent forward curve. The next two paragraphs offer a detailed explanation of our methodology, which you can skip if you are already familiar with these topics.

Statistically, we detect a highly significant relationship between OECD oil inventories and the Brent futures curve’s position and shape. Higher than normal inventories are associated with a Brent contango, which occurs when early delivery futures prices are lower than those for later months, creating an ascending futures curve. Contango incentivizes the storing of oil to cover the cost-of-carry of oil for future consumption. Conversely, lower-than-normal inventories are associated with backwardation, which happens when futures prices for early deliveries are higher than those for later, resulting in a descending futures curve, which we have seen since March 2021.

Backwardation yields a financial premium for those that carry oil in storage and also a ’convenience yield’ for those that need to consume oil, for example, refineries, airlines, etc. To understand the role of speculation, it is crucial to remember that in backwardation the ’roll yield’ - a financial return produced by rolling a long position from an expiring futures contract to the next futures contract, is positive, while in contango it is negative. The roll yield then acts as a sort of catalyst for speculative activity. In backwardation, it incentivizes speculators to pour more money into the commodity, a process which normally steepens the backwardation further, thus making the roll yield even larger, which then attracts even more speculators, in a self-reinforcing process that usually ends when the inventories are no longer tight. The opposite happens in a contango, with speculators exiting the commodity in rising numbers as the roll yield turns increasingly negative. Note that in the presence of extreme events, backwardation and contango can “blow out” from the normal $5-$7 per barrel range. The chart below shows the onset of a super-contango right after the Great Recession in 2009 and after the Covid-19 pandemic in April 2020. Until March of this year, the markets had not experienced a super-backwardation for the past 20 years, not even during the Arab Spring in the early 2010s. 

This ’excess risk premium’ can then be recorded as an additional backwardation on top of what the historical relationship with the OECD inventories would suggest. The risk premium rose to $20 per barrel on 8 March, less than two weeks after the invasion of Ukraine, when the West began to sanction Russian oil and front month ICE Brent closed at $128 per barrel. Hence, we label the excess premium as the RRP. For the past four months, the RRP has averaged around $12 per barrel, also an unprecedented tally. Currently, it is still in the $10-$15 per barrel range, although it remains far from constant. On some trading days, it narrows due to recession and inflationary fears, as it has the past couple of weeks. On others it can widen on the back of high refining margins, which are insanely attractive and scream for higher refining runs, boosting demand for crude.  

But what about gas? Is there a way out?

How do we go from the current riptide market to calmer, levelized natural gas prices in the future? While upward trending prices have become commonplace, the European government has not committed to any firm plans to ensure an abatement. That’s because there simply are not enough alternative sources for Europe to replace Russian gas. Each country has its own regime and while some countries have already implemented measures to slow prices, like Spain introducing a price cap in June and Germany entering the second phase of its emergency plan, we are likely to see gas rationing very soon, and additional price caps going forward.

The European administration is walking a tight rope with Russia now and rekindling relations will be complicated – but so too are the complications associated with the lack of proper energy resources to make it through the winter. While there are too many geopolitical uncertainties associated with current market fundamentals, it is difficult to postulate a formula for success – even though the need of the hour calls for one. The EU and Russian leaders must come to an agreement, and soon. Europe has managed through the summer with reduced gas flows from Russia but will need to ration supplies this winter and could be out of gas next winter. If the NordStream1 pipeline flows remain offline after its ongoing planned maintenance this month, and with the Freeport LNG facility offline indefinitely, markets are set to become even tighter.

RRP and its impact on the US

The RRP on US natural gas is hard to quantify because the market is largely isolated from global trends and driven by regional factors. Still, the surge in demand for US LNG, particularly from Europe in response to weaker Russian flows, is one of many factors contributing to higher domestic prices.

The global LNG market was already tight even before the Russia-Ukraine conflict. Over the last few months, western Europe’s import capacity has reached over 100% as a response to the deficit in the market. And following the invasion, Europe is looking even more to US LNG as an alternative to Russian gas flows. Most of Europe’s incremental supply is getting shipped from the US, accounting for roughly 65% of region’s LNG imports in recent months, doubling from an average of 30% last year. This increase is largely attributed to flexible US supply that has allowed volumes to be re-directed to Europe in the short term and we anticipate the majority of exports will continue to redirect to Europe. 

For a time, the US was able to stave off the effects of high prices, but the momentum ultimately carried over, pushing Henry Hub prices to historic highs as limited domestic supplies and low storage inventories, alongside heightened demand locally and abroad applied upward pressure to prices. Although recent high prices in the US are related to the rapid increase in LNG exports, US markets are still largely driven by regional market fundamentals. This recent price volatility is more linked to weaker incremental dry gas production for increased domestic demand, as warmer weather drives up gas consumption, and lower storage inventories at the start of injection season. Now, with the Freeport LNG plant outage, nearly 2 billion cubic feet per day (Bcfd) of gas will remain within the country, helping balance the domestic market and soften prices. The Freeport LNG outage and its ripple effects are just another indicator of the importance of US natural gas as a vital energy resource globally. Nearly 20% of US LNG export production comes from this facility and 2.5% of Europe’s total gas demand, highlighting how downtime from just a single plant can be felt around the world.

The global market will continue to see limited supply in the next two to three years, even with steady US production growth and LNG exports. Supply in the US, both onshore and offshore, is reacting to the RRP – and the most viable option is to increase production, so this does not come as a surprise. However, many setbacks have and are preventing this from happening quicky. There have been steady increases in production in the US already this year, but we need more if we want to see lower prices domestically and abroad. Further weighing on prospects of increased supply is the dearth in M&A activity. In a market environment inundated with volatility and risk, participants are hesitant to pursue opportunities. More activity, and really, more investment in energy, requires stability in prices.

Analyst spotlight

US Production & Supply Chain issues

Thomas Parambil Jacob, Senior Vice President, Shale Research

Operators in the US lower 48 states have seen significant increases in well costs due to tightness in the oilfield space such as directional drilling services, pressure pumping, proppant and OCTG, pushing up drilling day rates. etc. The pressure pumping market remains sold out for the rest of the year and this has led to service pricing increasing rapidly, exceeding pre-Covid-19 levels, with expectations to get past 2018 levels by year-end. There has been a moderate build-up in drilled but uncompleted (DUC) wells for private operators through the first half of 2022. This is counter intuitive since the current commodity market should suggest an opposite trend. Private operators are drilling wells at a faster rate than they can put them on production. Fleet availability is the biggest reason for this trend, providing strong evidence for sustained fracking activity through the second half of 2022.

Private operators have also seen significant increases in well costs, of about 30% to 40% year over year, in comparison to 15-25% for public players. Capital discipline and no increases in drilling and completions activity and production targets for 2022 have ensured no major exposure to spot market pricing for public operators. Public operators can expect higher service pricing as 2022 contracts expire and new agreements are renewed during the budgeting season for 2023. Conversations with operators have suggested moderate increases in production targets, of 5% to 10% year over year. Well cost inflation, supply chain bottlenecks, capital discipline and other factors will likely lead to conservative increases in drilling and completions for 2023 for public operators. Private operators will continue to ramp up and expand drilling and completions programs to take advantage of the higher commodity prices.

US Lower 48 oil production, excluding Gulf of Mexico volumes, is forecast to increase by about 1.4 million bpd from end-2021 to December 2022, with additional 1 million bpd increases in 2023 and 2024. There will be some easing of supply chain constraints next year, with new frack fleets and frac sand supply hitting the market. The argument against Lower 48 production growth is the increase in private operator market share leading to lower well productivity as private players do not have access to Tier I acreage in the US. The sheer magnitude of increases in well completions from private operators and the expected increase in well productivity from longer laterals and full-scale development by private operators in the coming months do suggest that the oil production growth story from the US remains feasible.

Offshore contracting activity on the rise

Liz Tysall, Lead Analyst, Energy Services Research

Steps taken in 2021 by some Middle East national oil companies (NOCs) to boost oil production are beginning to take shape. Both Saudi Aramco and ADNOC are increasing offshore contracting activity by adding incremental jackup supply and renewing contracts for their existing rig fleet. Since the fourth quarter of 2021, just under 200 rig years of contracts have been added offshore in Saudi Arabia and the UAE combined with contract durations varying between three and five years in length. NOCs in the Middle East are ramping up offshore activity as one avenue to increase production. Total offshore production is expected to grow at the rate of 3% towards 2025 for these two MENA countries.

Because of the relatively short-cycle nature of projects in the Middle East, the NOCs can react faster to market dynamics. As a result, the jackup market is the key beneficiary of the Middle East NOCs hunt for additional barrels. Twenty-six percent of the world’s jackup demand is driven by Saudi Arabia and the UAE. This burst of contracting activity has so far brought in 30 jackups which were either idle or located outside the region. This in turn has led to considerable growth of the offshore fleet size for local drilling contractors. The last time there were contracts awarded approaching these volumes in these two countries was 2018 at just over 110 years. Many of the fields have a breakeven level below $40 per barrel meaning that offshore rig activity in the region will continue to be resilient.

M&A trends mixed

Thomas Liles, Vice President, Upstream Research

The RRP and overall tightness in the market have had a predictably chilling effect on upstream M&A activity this year, with the aggregate value of deals announced during the first five months of 2022 down nearly 40% compared to the same period last year. Nevertheless, deal making rebounded somewhat in June and increased to more than $15 billion for the month, led by an uptick in North American transactions as well as a scramble among upstream players to secure stakes in Qatar’s North Field East (NFE) expansion.

The majors have primarily been in divestment-only mode since the onset of the pandemic and have been on the selling end for at least 25% of aggregate deal values this year, up from 12% during the first half of 2021. As such, elevated benchmark prices may prove to be more supportive of the majors’ longer-term divestment goals. Indeed, BP kicked off the year by divesting its 50% non-operated working interest in Alberta’s Pike oil sands lease to Canadian Natural Resources, and in June the British major sold its stake in the Sunrise oil sands project to Cenovus in exchange for a hefty cash payment and Cenovus’ non-operated stake in the Bay du Nord project offshore Newfoundland and Labrador. BP’s recent moves raise the prospect of continued flight from the oil sands by the majors. TotalEnergies has intermittently expressed interest in selling its non-operated stakes in the Fort Hills mine and the Surmont SAGD project, although market volatility in Western Canada since 2018 has hurt the attractiveness of such transactions from a valuation perspective. In the shale space, ExxonMobil has pushed ahead with its $25 billion divestment plan by 2025, offloading its shale assets in the Barnett, Montney, and Duvernay plays for a combined $2 billion in the second quarter.

Meanwhile, the majors have been at the opposite end of several transactions involving Qatar’s NFE expansion since early June, underlining the long-term value proposition of LNG as Europe seeks to secure more reliable sources of long-term natural gas supply. QatarEnergy awarded a stake in the massive LNG expansion first to TotalEnergies and subsequently to Eni, ConocoPhillips, ExxonMobil, and Shell for a combined estimated valuation of nearly $7 billion. Wider market turmoil notwithstanding, there are clearly several bright spots in the M&A space.

So, what could be done, if anything, to address the high prices associated with the RRP?

Some market hawks and politicians are calling on the Biden administration to reimpose a crude export ban to reduce oil prices. In our view, such a move would be self-defeating and will only exacerbate the global oil shortage. As we illustrated above, a tighter global oil supply would force an even steeper Brent backwardation and therefore push spot prices even higher. On the other hand, WTI – the US crude oil benchmark – would most likely flip into contango as the production in the Permian would be trapped in Texas. The WTI-Brent spread would then widen to unprecedented levels, likely exceeding the $30 per barrel record set in the early part of the 2010s, when the crude export ban was still in place. This would disincentivize US domestic production of crude and would also result in a massive transfer of profits to US refiners at a time when they are already making historic margins – in an order of magnitude higher than normal – due to a global refining capacity shortage.

And what about the consumer: would they at least get some benefits at the pump?  They would not. US gasoline prices along the East and West Coast, where most Americans live, are set internationally, via an import parity mechanism, Hence, they would be pushed even higher as a result of the increase in Brent prices. In the end, a policy designed to reduce domestic gasoline prices – at the expense of a massive loss in efficiency and competitiveness of American oil producers – would result in higher gasoline prices for most American consumers and an even stronger RRP.

Could then a recession cut the RRP? It would possibly reduce it for the duration of the recession, as recessions usually weigh on oil demand growth, making S&D balances looser. But it is unlikely to structurally erase it. Indeed, as soon as demand bounces back, the RRP would reappear, unless its root causes were addressed and removed.

Given that we have identified the expectation of a structural decline in Russia’s oil and gas production as the basis of the RRP, the only solution can either be an increase in production elsewhere in the world, which fully compensates for the drop. Or Russia’s production remains resilient and there is no drop eventually.  A third option is not available, unluckily. We talked about the first option in one of our earlier Review editions, highlighting how the US and the Middle East will struggle to fill the gap in the next couple of years especially if the drop in Russian volumes turn out to be large – 2 million bpd in oil output or more. In our June issue of Review, we also showed how a price cap on Russia’s crude exports could theoretically keep the country’s production flowing at current levels while at the same time prevent its regime from benefiting from rising oil prices. The Group of Seven, has been exploring this solution, spearheaded by US Treasury Secretary Janet Yellen, although the path forward appears narrow. That is because, for a price cap to work, all major countries need to abide by it, while the geopolitical implications of dealing with Russia in terms set out by the West- may easily break the required cooperative behavior. Crucially, a price cap is a measure that directly interferes with the market mechanism for price formation and could create a powerful precedent, of which oil and gas producing countries may be wary. In option two, bringing back and allowing Russian oil and gas to flow to Europe again would be easier said than done given the stance Europe and the West has taken.

In conclusion, there is no quick solution to the high oil prices resulting from the RRP. Either production increases in the US, Middle East, and South America. But that will not happen overnight. It will require sizable investments and, more importantly, willingness to commit to long-term oil and gas projects, which investors and lenders seem to be wary of given the growing calls for more climate action. Or, world leaders allow Russia oil and gas to continue to flow at the same levels as before, and attempt to institute a price cap to limit the financial benefits on the Russian regime, if they can agree on that. Any other option, including a recession, will not be a structural solution, and would be doomed to fail.

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Authors: 

Claudio Galimberti  

Senior Vice President of Oil Markets, Head of Americas Research 

claudio.galimberti@rystadenergy.com

Emily McClain

Vice President of North America Gas Markets Research 

emily.mcclain@rystadenergy.com 

Thomas Parambil Jacob

Senior Vice President, Shale Research

thomas.jacob@rystadenergy.com

Liz Tysall

Lead Analyst, Energy Services Research

liz.tysall@rystadenergy.com

Thomas Liles

Vice President, Upstream Research

thomas.liles@rystadenergy.com

(The data and forecasts contained in this column are Rystad Energy’s and the opinions are of the authors.)