- Crude prices continued their ascent to close the period at their highest level in four years when spot prices peaked at $85 /bbl in October 2018.
- Dated Brent prices have already increased 25% this year to date and the wind remains in the market’s sails amid surging petroleum products’ demand by South East Asian and Western economies racing to lift lockdown restrictions. In spite of OPEC+ agreeing in July to lift the cartel exports by 400,000 barrels a day, prices continued to stay firm due to Japanese and Chinese buying for oil-fired power plants.
- Black-outs: The market was spurred on last month by reports that specific Chinese provinces, representing some two thirds of China’s GDP, had been hit by black outs in recent weeks, fuelling a general scramble for back-up power generation supplies including coal which, as a competing fuel to gas, tightened the international LNG market further still.
- Oil injection: An affirmative, Saudi-led supply impetus from OPEC + aimed at preventing the oil market spiraling from this point on is looking very 50-50. The cartel has every incentive to do the responsible thing given the fragility of both the world’s energy supply and financial systems although question marks over the cartel’s final capacity to deliver remain.
- Higher oil prices have been sustained for some months now. From a contractual angle, Russia will prefer ‘modestly high’ prices (of circa $75/bl) which are sustainable to higher levels which aren’t.
- Operative contract prices in (soon to be signed) long-term 15 to 25 year gas sales agreements will be set against higher current or prevailing gas market prices on signing, thereafter escalating with changing petroleum and other commodity price indices included within the indexation basket.
- European buyers evidently face a supply squeeze. This is due to Russia’s reluctance to release extra volumes through Ukraine, although predictably, rising demand and poorly replenished gas storage inventories have also played a part.
- Many utility buyers across West, Central and Eastern Europe who hold existing long-term Russian contracts will be maxing-out their contract volume entitlements. Volumes obtained under contract will be much cheaper than the over the counter (O.T.C) gas market prices. Contract buyers will be optimising their Russian take-or-pay contracts to the hilt by nominating the full 100% take-or-pay volume, calling-in any swing flexibility negotiated and/or exploiting carry-forward provision that may allow the buyer to call on unused take-or-pay entitlements from previous years in some cases.
- Gazprom is probably more contractually-constrained than headlines suggest. It also has supply issues of its own to deal with and inventories across the continent are reported unusually low given the time of year. That said, Russia could be doing more and a certain amount of sabre-rattling is at play over the NordStream 2 project. The situation on the ground is probably more complex than what is generally reported. It is this uncertainty that is pushing the market to extremes as the problem has no defined or rational end. Even though it is likely that the Russians will finally behave commercially and pragmatically, just as they always have in the past.
- Firming gas demand, historically low storage inventories across Continental Europe (barely 70% full) and physical limits on Norwegian and Russian producers to increase short-term exports (held up by delayed maintenance programs over the past 18 months) all play a part in explaining the staggering price rises on the O.T.C. market. The October Year contract rose another 25% over the quarter and is now up 96% this year.
- The UK itself is in a particular predicament in regard to storage. Now with far less in volume terms than any other major European country following the closure of its only asset at the Rough field four years ago. The decision to close Rough stems from a host of reasons including a ‘perceived abundance’ of gas on the world stage, upgraded LNG import terminals as well as inter-connectors to the Continent but it has to be said there was also a political reluctance perhaps for government support for a major fossil fuel project.
Forward power prices charged ahead rising 30% over the last quarter. The annual base-load contract is now up 85% since the 4th January. The wholesale electricity market was buoyed by rising oil and gas prices, together with lingering worries over the ability of the UK power system to cover the peak-day demand call as the economy opens up.
Prices rose in response to lower-than-anticipated wind generation volumes during September, recorded at 60% lower than over the same period last year. This was also due, in summary, to:
1. Low winds speeds in the Irish and North Sea;
2. Concerns over security of supply due to delayed power station maintenance (the backlog a casualty of the pandemic);
3. The shock loss of 1 GW when the IFA-1 interconnector to France failed due to fire (set to stay down for 9 to 10 months);
4. Early closure, for safety reasons, of aging AGR-design nuclear power stations together contributed to supply availability concerns, which actually saw UK power prices trading in thousands of pounds per MWh over multiple delivery periods last month.
Past editions of Energy Highlights have already stressed reliability concerns about electricity interconnectors even using the latest, state-of-the-art technology with the UK already connected to Norway, Denmark, Belgium, and Holland, France and in a few years to be joined by further cables to Iceland and potentially Morocco.
Energy Storage in the UK
The UK supply mix entailing renewable energy, seabed inter-connectors and low-flexibility nuclear power will all be adding impetus to expanding energy storage at grid level. As the system becomes more decentralised, we should see demand evolve around distribution network assets, micro-grids and commercial sites too. In the past, the UK has relied on a centralised market with the onus on the generator to balance the system. But tomorrow could see this ‘Supply Sell’ market complemented by an offsetting ‘Demand Sell’ market with industrial, commercial and even domestic supply-interruption: demand reduction at micro-grids and battery-storage.
Hydrogen, Lithium-ion and Electricity Storage
● Of the scientific fields relating to electricity storage, the most interesting include lithium-ion and the possibly understated alternative, vanadium redox-flow as such batteries offer environmental, reliability and flexibility advantages over the former.
● Hydrogen is an energy carrier (not a fuel). As such it can be matched alongside other fuel cells. Hydrogen has very significant energy conversion losses along its (convoluted) supply chain however as the electricity generated to produce the hydrogen, which is then stored, then transported to source and then reconverted back to electricity before the point of use.
● Hydrogen is highly electro-intensive and very expensive to produce, especially at today’s O.T.C. prices. It may well have a niche role in terms of off-peak storage for wind turbines and nuclear power stations. However, we foresee lithium and vanadium as the only realistic front runners, certainly in commercial or in any domestic setting where hydrogen’s serious health & safety drawbacks have been understated in our view.
About the Author
Dominic Whittome is an economist with 25 years of commercial experience in oil & gas exploration, power generation, business development and supply & trading. Dominic has served as an analyst, contract negotiator and Head of Trading with four energy majors (Statoil, Mobil, ENI and EDF). As a consultant, Dominic has also advised government clients (including the UK Treasury, Met Office and Consumer Focus) and private entities on a range of energy origination, strategy and trading issues.
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