LONDON (ICIS)--European CCGT profitability for the first half winter will likely surge as gas prices for delivery over the fourth quarter are set to tumble on a stronger LNG outlook.
Power curve prices have lost some of their bullish momentum throughout the third quarter but CCGT margins are likely to remain the highest in France as nuclear risk lingers.
European gas market premiums over the US Henry Hub have rocketed in August with the Dutch TTF month +2 contract trading over $1/MMBtu above the North American benchmark at times. This is likely to encourage stronger US LNG exports into northwest Europe with greater economic incentive to ship cargoes across the Atlantic on wider margins.
This could have a bearish impact on European gas prices going forward and be a boon to gas plant profitability.
Norwegian maintenance, combined with a continued lull in LNG imports into northwest Europe, has bolstered European month-ahead markets with the front-end also boosted by recent hot weather.
The TTF and British NBP September ’20 contracts have surged 30% and 33% respectively since the start of August.
This is on top of strong gains which were also recorded late July.
A slowdown in volumes placed into storage facilities since July has provided shippers with greater anticipated injection demand for the months ahead which added further strength to European hubs.
This increase in gas prices at the front-end also filtered out across fourth-quarter delivery gas contracts which dented CCGT profit margins in August and further out.
However, despite the strong increase in hub prices a resilient carbon market throughout August prevented gas plant profitability from dropping further.
The Dutch Q4 ’20 clean spark spread fell 36% to €4.56/MWh month to date while the equivalent Italian clean spark dropped just 3.7%. Clean spark spreads measure the profitability of gas generation by calculating the wholesale price of electricity minus the price of natural gas, minus the price of carbon.
Bulls on shaky ground
Downside risk on gas contracts however has been increasing in recent sessions with fundamental support waning and an improved supply outlook ready to weigh on products.
Key to the lower EU and British injections has been increased use of backhaul flows at the Slovakia-Ukraine border, as shippers looked to access capacity in the east.
Net flows to Slovakia dropped from more than 60mcm/day in July to less than 25mcm/day though much of August. When accounting for Ukraine, sites across the continent are still holding around 8% more than they were at the same point in 2019 and the most ever for the time of year.
Flows to Ukraine should fall back in September due to maintenance on the Budince point from 1-21 September, which could support injections in the rest of Europe.
Month-ahead and Q4 gas contracts may be exposed to further weakness in the coming weeks as participants eye greater LNG imports.
European LNG imports totalled 5.4m tonnes (mt) in July, excluding Turkey, according to LNG Edge. This was 1.3% higher that the same month last year and fractionally above June. LNG imports averaged 7.5mt between January-May, which then dropped to 5.2mt in June as US LNG cancellations kicked in.
Between January and April, US LNG share into Europe averaged 30% as wide price differentials between the Henry Hub and TTF boosted deliveries.
The TTF Month+2 premium over the Henry Hub averaged $1.6/MMBtu in January and $1.1/MMBtu in February.
Between June and August to date, the share of US LNG in European imports dropped to just 13%, with little to no margin on offer for sellers.
Towards the end of August, the imminent arrival of Hurricane Laura at LNG export infrastructure in the US Gulf Coast sent prices on both side of the Atlantic higher once more. However, plants will likely be resilient enough to resume operations in time for October delivery. A number of producers in Gulf reduced operations in advance of the arrival, with the five-train Sabine Pass plant suspended. Other plants were running at reduced operations. Loadings at the terminals had already been reduced before the hurricane owing to cancellations from offtakers.
Market sources told ICIS they were not expecting cancellations to run into October, following the improving prices spreads to Europe and Asia.
Offtkers typically have 40 days before loading as a deadline to inform sellers of a cancellation, a deadline which would have passed for many by end of August. As many as 22 cargoes are expected to be cancelled for September, down from over 50 in July. The contango in the TTF curve could also be attractive enough for traders and offtakers to use September or October cargoes as floating storage, potentially waiting to late October-November delivery.
Strong spot LNG interest from India and China have boosted Asian prices, which has increased spreads to North America and Europe.
The EAX premium to the TTF for October delivery averaged $0.65/MMBtu in August, before moving to more than $1/MMBtu in week 34.
This could pull more US LNG towards Asia during the early part of the winter, with the spread to Europe wide enough to absorb the additional shipping costs.
Europe’s LNG import share reached 27% in April, the highest proportion recorded, with Asia accounting for 58%. This has changed in recent months with Asia accounting for more than 60% since June and almost 64% in August. An increasing European discount to Asia could also spark an uptick in reloads if economics prove favourable.
German utility RWE is poised to benefit from a weaker gas market as it plans to bring the Dutch 1.3GW Claus C gas-fired power plant back to full market availability for October 2020, despite the government rejecting plans to link the plant to the Belgian grid.
The Claus C power plant is a 1.3GW gas-fired unit located in Maasbracht, the Netherlands.
In July 2014, the plant was mothballed for economic reasons, according to RWE website. In October 2018, RWE decided to bring the plant back into operation from October 2020 onwards due to the need for flexible power generation.
In August 2019, RWE submitted an application to link the plant with the Belgian grid. This would enable RWE to access Belgian capacity payments and support Belgian supply security, which might be affected by the nuclear phase out plan. An underground high-voltage cable would be built to connect the Dutch plant to a switching station in the municipality of Kinrooi, Belgium.
In July 2020, the Dutch Economic Affairs Ministry confirmed that the government had rejected the appeal by RWE to link the plant to Belgium. Reasons included technical objections made by Dutch transmission system operator TenneT related to risks to power flows on the high-voltage network. However, the project is still under discussion and could possibly start by the end of 2021, a press officer from RWE told ICIS.
The Claus C plant has already been partially brought online to fill the gap left by the 2.3GW Rotterdam coal plant. The coal-fired asset has not run since it utility Engie sold it to American company Riverstone Holdings in 2019, an energy consultant told ICIS.
Power supply in the Netherlands is highly dependent on gas-fired generation, which accounted for 60% of power produced in the country in 2019.
Dutch clean spark spreads have decreased over the summer. They stood at their highest level on 16 June at €5/MWh, before declining by more than 50% to reach €2.3/MWh on 14 August.
Despite this decline in gas plant profitability, flexible generation is needed in the Dutch system due to growing intermittent renewable generation. Between 2016 and 2020, onshore wind capacity grew by 21%, offshore wind by 379%, and solar by 300%, according to installed capacity data from ENTSO-E.
In the UK, two plants totalling 1.5GW of gas-fired capacity were mothballed by KPMG after owner Calon Energy went into administration. The closures more reflect the nature of the ageing assets rather than a general decline in gas-fired generation profitability in Britian. The two plants were designed as baseload generators but had been competing, largely unsuccessfully, against other forms of flexibility. Data from system operator National Grid showed the facilities had generated 78MW combined on average this year via balancing actions. Plants with more efficient engines and those specifically designed to meet peak demand had effectively made the two older units uneconomic.
Gas in the UK remains the dominate thermal generation, with the network running without coal for 55 days in a row up to 12 August.
Calon Energy also operate the 582MW Baglan Bay facility, which is expected to continue to run as normal.
French nuclear risk
European power Q4 baseload products have declined since the start of July with the sharpest losses observed in the French market amid increased confidence in winter nuclear availability.
Earlier ICIS analysis highlighted uncertainty in the second quarter as energy giant EDF responded to the coronavirus outbreak by revising its nuclear schedule. French power prices were at a strong premium to its neighbours with imports and gas demand set to be supported.
In the third quarter, some of that risk has dissipated with fewer large-scale adjustments to nuclear forecasts, strong hydroelectricity stocks and sluggish electricity demand recovery. This has seen the Q4 baseload premium to the UK equivalent drop from €14.40/MWh on 1 July to €0.80/MWh on 19 August. UPDATE Part of that squeeze has also stemmed from the UK power curve being forced up by the bullish momentum in gas.
Looking ahead, the French Q4 baseload will struggle to outturn below its UK counterpart with some uncertainty over nuclear output still lingering.
“Gas is still cheap and the risk is clearly in France – the UK also has a lot of wind installed, above 24GW. The UK is also protected by the capacity mechanism,” said one trader.
The mechanism provides financial incentives for power plants to be kept on standby and ready to provide back-up electricity during peak levels. Generation was secured close to target levels for this year.
Italian dry spell
Expectations of a dry outlook with above-average temperatures are likely to boost gas-fired power plants’ generation in Italy in September.
This comes after expectations of a limited demand rebound and an upswing in gas had progressively eroded Italy’s September ‘20 and Q4 ’20 clean spark spreads.
Between 1 July – 6 August, the September ’20 clean spark spread narrowed by 6% to €14.50/MWh, with the front quarter clean spark dropping 16% in the same period to €11.60/MWh.
However, increasingly depleted hydropower reservoirs may open more space for thermal capacity in the mix, especially in the event of temperature spikes and low renewable production.
Poor hydro output in August so far had already supported CCGT production during week days, which saw an increase of 3.8% compared to the same period in 2019.
Hydro generation in August so far saw a 4.5% drop compared to the same period in 2019, Italian TSO Terna data showed.
This was mainly due to below-average hydro stocks fullness and temperatures above the seasonal norm in past weeks.
Italian water reservoirs were 56.25% full as of week 32, ENTSO-E transparency platform data showed. This was four percentage points below 2019 levels and five percentage points lower compared to the previous 10-year average.
Temperatures are set to remain above the seasonal norm throughout September, according to the EU Copernicus service’s long-term forecast.
According to LNG Edge, Italy’s LNG imports in July increased year on year for the second month in a row. This was despite cancellations of US LNG cargoes directed towards Europe due to crumbling demand as lockdown measures were put in place across countries. An ongoing favourable spread between the PSV front-month contract and ICIS spot DES Italy LNG price suggest Italy will likely remain an attractive hub for LNG imports in Europe in the months ahead.
Top of the stack
Despite a sustained recovery in EU hub prices through July and August, gas has maintained its position as the key fuel of baseload thermal generation.
With record amounts in store and US LNG primed to return to the supply mix, gas this winter is unlikely to be displaced. But competition from zero marginal cost renewables and most efficient coal and lignite plants is never far behind.