INSIGHT: Economic argument behind Russian gas flow fluctuations

Author: Christopher Rene


LONDON (ICIS)--Fluctuations in piped gas supplies have been one of the main drivers behind price volatility on European hubs and strongly contributed to record high prices this winter.

The supply picture for Europe at the start of the winter appeared bleak. Natural gas stocks across the region were languishing at all-time lows with sites only 72% full on 1 October, a 22-percentage point drop year on year, and 18 percentage points below the 2018-2020 average.

At the same time, gas prices for Day-ahead delivery had hit new highs with the ICIS TTF product assessed at €85.40/MWh the session before.

The market was particularly sensitive to lower Russian gas flows entering Germany via the Yamal pipeline and Slovakia via Ukraine.

At the start of the gas winter, Russia delivered an average of 335m cubic metres (cm)/day of gas into Europe in October and had surpassed Norwegian flows (331mcm/day) and LNG sendout (198mcm/day), ICIS-collated data shows.

But by February flows had plummeted with an average of 240mcm/day delivered across the month. In contrast, Norwegian flows were 329mcm/day and LNG sendout was even higher with 416mcm/day.

In addition, Russian flows have not yet surpassed any of the volumes recorded during the previous winter.

European supply margins across October 2020-March 2021 were under pressure as a lack of LNG supply, combined with periods of below-average temperatures, triggered high gas withdrawals and weakened natural gas stocks.

Russian gas helped to alleviate some of this pressure with the monthly range for October 2020 to March 2021 at 387-460mcm/day. However, for this winter period up until February the range has been 240-348mcm/day.

Several market experts said the fluctuations in Russian flows are related to pricing enshrined in Gazprom’s long-term contracts with European buyers.

ICIS understands that Gazprom’s long-term contracts still have a higher share of pricing linked to oil products compared with other producers, such as Norway’s Equinor, whose contracts are linked to hub prices. In the current market conditions oil indexation makes Russian long-term contract gas cheaper than alternative piped gas supplies.

Morten Frisch, senior partner at Morten Frisch Consulting said on social media that high oil and European gas hub prices have eroded the desirability of Gazprom’s long-term contracts that are linked to them and discouraging associated nominations, which translated into lower flows via Yamal and Velke Kapusany.

“Most if not all hub-indexed long-term contracts will now include hub price data for November and December last year when prices were “sky high”, hence buyers under these contracts could now be losing money on these high-priced supplies in the current European gas market. It is currently better for buyers under these Gazprom long-term contracts to source their gas supplies from LNG imports,” Frisch said.

“Applicable invoice prices under all of Gazprom’s long-term contracts, whether with 100% oil price indexation or European hub gas price indexation or a mixture of the two, are currently all at the highest level they have ever been or very high. At the same time Russian gas exports are currently very low due to a combination of gas production problems in West Siberia and buyers’ low nominations under hub indexed long-term export contracts,” he added.

Meanwhile Russia’s share of the market has been under threat, initially by domestic production disruptions and then by the influx of LNG into Europe.

ICIS data shows that Day-ahead prices switched from trading at a high premium to front-month index deliveries in December to large discount in January.

The switch coincided with a significant jump in LNG sendout across Europe as high hub prices towards the end of 2021 encouraged producers to ship flexible cargoes into the region, boosting short-term supply margins.

The transition would have provided a strong incentive for holders of Gazprom’s long-term contracts with month-ahead indexation to turn down the contract where possible and source gas from the spot market.

Since the beginning of February, the spread between the Day-ahead and front-month index values has narrowed significantly, which could reverse this incentive once again.

However, flexibility is limited for buyers who currently hold these contracts with further opportunities to down flows likely to be lower moving forward.

After low January flows due to long-term contracts linked to a month-ahead index being so out of the money, many of the buyers with those long-term contracts will have used up a lot of the flex in their agreements to not nominate the gas, a trader told ICIS.

The source added that buyers may be likely to nominate flows this month even if the Day-ahead is a bit below where the front month outturned in the previous month, just because of the limited flexibility in their contracts, and not wanting to run out of days where they can turn down flows which they may want to use for public holidays later in the year.

The spike in spot prices relative to forwards represent a conundrum for Gazprom.

Elevated prompt prices could be an incentive to sell extra spot gas, but this could also undermine its overall revenue from long-term spot-linked contracts.

In one of its Investor Days last year, Gazprom announced that 56.1% of its export portfolio was linked to the Day-ahead and Month-ahead contracts, 30.9% was linked to forwards (quarter, season and year) and 13% was indexed to oil.

Sources told ICIS that requests for Gazprom to sell more spot volumes on its Electronic Sales Platform (ESP) had been declined by the utility, but it was keen to negotiate long-term (3-5 year) agreements further.

In contrast, Norway has pursued a strategy which has resulted in higher gas volumes being sold on the spot markets. Tight European supply margins for most of the winter have galvanised the uptick while the expiry of long-term contracts is another factor.

Previous ICIS analysis shows that the expiry of French and UK supply agreements will pave the way for Norwegian pipeline supply to Europe via long-term contracts dropping from 4 billion cubic metres (bcm) in 2021 to around 44bcm this year to approximately 15bcm by 2025, according to data collected by ICIS Analytics. According to preliminary figures, only 40% of Norwegian gas exports were under long-term contracts in 2021 .

According to ICIS modelled calculations, Russia remains the most competitive source of pipeline gas. German imports for March ’22 delivery of Russia gas was €34.03/MWh, €27.1/MWh cheaper than Norwegian supplies.

Why would a gas producer ever want to cut back on its gas sales when prices are at record highs? And why would a buyer not want to take more gas when their storages are running low and there are concerns about security of supply?

The explanation could lie in the different purchasing mechanisms through which gas is traded. Gas supplies to Europe are either supplied in the spot market or on long-term contracts. Spot market sales are agreed shortly before delivery at a fixed price, for example a deal is done for gas for the next month at €100/MWh.

In a long-term contract, the parties agree to receive a certain amount of gas over the next five, ten or 20 years with the price to be settled each month over that period. The price can be calculated and paid based on various index mechanisms, for example each month’s long-term contract cost could be set by the previous month’s average spot price.

Now imagine that a long-term supplier is selling ten units of gas into the market on a long-term contract priced at €80/MWh. They will make €800 of revenue. If the producer had some spare gas, they could consider selling that into the market, but they would risk the possibility that the extra gas would lower the spot price.

If one extra unit of gas lowered the spot price by €5/MWh, then selling the extra unit would boost their overall revenues by €25. But if the extra unit of gas lowered the spot price by €10/MWh, their overall revenue would drop by €30/MWh, despite having sold more gas.

Long-term gas contracts usually have an element of volume flexibility. The buyer can request slightly higher or lower volumes each month, or reschedule them within the length of the contract, to meet fluctuations in demand, such as caused by the weather. Buyers will each month evaluate the opportunity of taking more or less long-term gas and buying more or less spot gas.

Imagine that a buyer takes their long-term gas on a price set by the previous month’s average spot gas price. If the market is on a downward trend, then the current spot price could be lower than the average spot price for the previous month.

In this case a buyer might look to reduce the volumes of their long-term contract as far as possible and buy cheaper spot gas instead. So even though they want more gas, they might not use their long-term contract to obtain it.

Could these contract mechanisms help explain reductions in Russian pipeline gas flows to Europe? The real situation is much more detailed and complex than the simplified models given here, and there are of course major geopolitical factors at play too.

However, even a simplified model suggests such mechanisms could be playing some part in determining flows. For example, the graph below shows the ICIS TTF day-ahead gas price over the last four months against the flows of Russian gas from Ukraine to Slovakia at the Velke Kapusany border point.

During October to December the daily TTF price was normally above the previous month’s average spot price, and there were strong flows of Russian gas into Slovakia. After the record price spike of mid-December 2021, the market fell back in January with an influx of US LNG cargoes.

The spot gas price was now below the previous monthly average, so it would have made economic sense for European buyers to prioritise spot gas market purchases over long-term imports, and Russian flows fell. At the start of February long-term contract prices based on January’s average became much more competitive again, and flows increased.

Sellers, therefore, could have little economic incentive to provide more gas into the spot market during market tightness, while buyers might wish to buy more spot gas, but prefer not to maximize their long-term contract flows.

Insight article by Christopher Rene.

Additional reporting by Katya Zapletnyuk, Kaja Sillett, Alice Casagni and Thomas Rodgers