Energy professional with 25 years of expertise across the oil, gas, electricity and renewables industry, chiefly by pursuing financial analysis, project development, supply and trading roles in major energy institutions, with extensive knowledge of the energy industry and a network of contacts across regulatory, technical innovation, private investment and end user groups.
Key roles and experiences include:
Private Energy Management Consultant
– Gas and electricity purchasing, long-term contract negotiation and risk-management.
– Commodity and capacity market analysis; administration of trading, supply and billing tasks.
– Due Diligence/M&A analysis relating to UK networks, generation and renewable investments.
– Project development of on-site generation, battery storage and efficiency saving projects.
Head of Gas Trading, Purchasing & Risk-Management at a large integrated energy company– Started up the company’s Gas Trading division in London. Managed around-the-clock department of energy traders and analysts to ensure supply to 3 million domestic and industrial customers.
– Grew gas division to establish the company as the UK’s 2nd largest physical supplier.
– Lead contract negotiator and trader of gas & electricity swaps with £2bn under management.
– Seconded to Corporate Finance team to evaluate network and nuclear electricity investments.
– Handled the company’s dispute resolution case concerning termination of gas and electricity contracts and helped recover circa £200m for the company.
Oil and Gas Field Sales Negotiator & Financial Analyst at a multinational oil and gas company– Negotiated offshore oil, gas and condensate sales, lifting and pipeline access agreements.
– Worked with field partners to manage the company’s equity stake in several gas fields.
– Initiated the company’s UK gas trading operation; undertook financial analysis of North Sea M&A deals, gas storage, interconnector, power generation and industrial gas & power marketing projects.
– Aided in the development of a pan-European strategy and UK gas trading platform.
Oil and Gas Sales Negotiator & Commercial Analyst at a multinational oil and gas corporation– Advised global affiliates on EU regulation affecting exploration, trading & refining businesses.
– Negotiated offshore sales & lifting agreements with equity partners and energy utilities.
– Conducted financial appraisal of investment relating to North Sea exploration, energy storage, interconnector, alternative transport fuels, domestic UK gas and electricity supply ventures.
– Involved in starting up the company’s pan-European Gas Supply and North Sea Spot Trading divisions.
North Sea Oil Operations Controller/Futures Market Analyst at a multinational energy company– Dealt with lifting and shipping operations for the oil supplies of several fields.
– Handled telex operations and prepared market research for 15-Day Brent and Futures trading.
Relevant Educational Background:
Master’s Degree – Economics of Finance and Investment.
Bachelor’s Degree – Economics.
Crude oil prices continued their ascent to close the period at their highest level in four years when spot prices had peaked at circa $85/bbl in October 2018. Dated Brent prices have already increased 25% this year to date. 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. Despite OPEC+ agreeing in July 2021 to lift the cartel exports by 400,000 barrels a day, oil prices were supported due to Japanese and Chinese buying for oil-fired power plants. The crude oil market was also spurred in October by reports that specific Chinese provinces, representing some two-thirds of China’s GDP, had been hit by blackouts in recent weeks. This fueled a general scramble for backup power generation feedstocks and refined products. Including lignite and black coal which, being competing fuels to gas, tightened the international LNG market further still. An affirmative, Saudi-led supply impetus from OPEC+ aimed at preventing the oil market from spiralling from this point where it is is still looking very 50-50. Whilst the cartel has every incentive to ‘do the responsible thing’ given the fragility of both the world’s energy supply and financial systems, there will remain question marks over the cartel producers’ final capacity to deliver on any export increases.
Gas prices rose another 25% over the second half of 2021 as the background oil market remained strong. The spotlight has been on Russia. From a strategic perspective, Russia would probably prefer modestly high oil prices (of circa $75/bbl) but not unsustainable prices that may impact long-term customers. From a contractual perspective, operative contract prices in (soon to be signed) long-term 15 to 20-year gas sales agreements will be set against higher prevailing gas market prices. So the new price environment benefits major gas producers on that count. European buyers are facing a supply squeeze, blamed on Russia’s claimed reluctance to release extra volume through Ukraine. However, sharply rising gas demand, inadequate infrastructure maintenance and poorly-replenished gas storage inventories have each played a part as well. Another factor would be utility buyers who hold existing long-term Russian contracts. They will be maxing out their contract volume entitlements, which will be much cheaper than spot or prompt volumes currently available on the O.T.C. These utilities will not only be optimising their take-or-pay entitlements but also calling in any swing flexibility or carry-forward provisions the contracts may offer, i.e. relating to unused take-or-pay entitlements dating back to the low-demand pandemic era. Therefore Gazprom may be more contractually-constrained than headlines suggest. Russia and many other major gas exporting countries also have internal energy supply issues to deal with. There is some element of sabre-rattling at play over the activation of Russia’s NordStream 2 project to Germany. But the situation on the ground is still probably more complex than generally reported. Such uncertainties are certainly pushing the gas market to extremes, even if it is likely that the Russians will finally behave commercially and pragmatically to protect their export market, just as they have all along. Meanwhile firmer gas demand, historically low storage inventories across Continental Europe (now barely 70% full) and physical limits on Algerian, Norwegian and Russian producers to increase their short-term exports (held up by delayed maintenance programs over the past 18 months) have all played their part in establishing some staggeringly high, if volatile, prices on the O.T.C. market. The October Year contract closed the quarter at 95p per therm and is now up over 95% this year alone. The UK is in a particular predicament in regard to storage. 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 low gas prices at the time; a perceived ‘abundance of gas’ on the world stage generally; upgraded UK LNG import terminals and new inter-connectors to the Continent. However, there was also a political reluctance perhaps for Westminster to be seen to be financially supporting a major fossil fuel project. Any loan required to reactivate the Rough field, unmaintained now for 5 years and the cushion gas is gone, would be colossal.
Forward power prices charged ahead, rising 30% over the last quarter. The annual base-load contract is now up 85% since the 4th January 2021. 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 peak-day demand as the economy opens up. Power prices rose in response to lower-than-anticipated wind generation volumes during September. They recorded 60% lower than over the same period last year. This was also due to lower winds speeds in the Irish and North Seas; concerns over the security of supply due to delayed power station maintenance (this backlog was another casualty of the pandemic); 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); further early closures for safety reasons of ageing AGR-design UK nuclear power stations which together contributed to supply availability concerns.
These events saw UK day-ahead power prices trading in thousands of pounds per MWh and over multiple delivery periods last month. Past editions of Energy Highlights have stressed a reliability concern about electricity interconnectors generally, even with the benefit of state-of-the-art technology. The UK is now connected to Norway, Denmark, Belgium, and Holland, France (twice and a third cable come 2025) and will be joined in future by further interconnectors to Iceland and potentially North Africa. This UK supply mix entailing renewable energy, inter-connectors and low-flexibility nuclear power will boost demand for grid storage. As the UK network becomes more decentralised, we should also see demand evolving around distribution network assets, commercial and potentially domestic sites/microgrids as well.
In the past, the UK has relied on a centralised market; the onus being on the generator to balance the system. Tomorrow could see this ‘Supply-Sell’ market complemented by an offsetting ‘Demand-Sell’ market with industrial, commercial, even micro-grids each selling their self-interruption/demand-reduction into the system and any such Demand-Sell market should encourage further uptake in battery storage.
Day-ahead gas prices momentarily traded over £2.50 p/th (December 7th 2021). The market was driven higher amid reports of surge buying by power generators, electro-intensive industrials and concerns about an imminent Russian incursion into Ukraine as well as US sanctions or other action affecting exports all coming to a head at once. Consequently, the O.T.C. market saw risk-premiums ratchet up along the curve. There had been some rest-bite for gas, conferred by a comparatively tame oil market. 15-Day Brent traded around a relatively tight $70 – 75 /bbl range. Aided by news last week that the OPEC+ cartel was still looking to make good on its earlier promise to increase oil exports by 0.4 million barrels a day from January onwards. In spite of ebbing demand expectations with the latest Covid variant threatening to suppress demand once more. However, it proved short-lived as fundamentals relating to physical gas availability itself predominated. Although bullish sentiment was abetted by news of new strike action planned for existing UK North Sea platforms and now future UK platforms bought into question by Shell’s decision to pull the plug on its 1.7 million barrel Cambo project West of Shetland. With question marks lingering over its nearer-term (2024) Jackdaw field as well, there is plenty to dishearten the bears just now.
Likewise, forward electricity prices have soared again with April Year contract volumes changing hands at near-term record highs, over £140 MWh (14 p/kWh), albeit shy of the £180/MWh ‘super-peaks’ we saw in late September. The prompt market meanwhile was jolted by warnings by French nuclear operator, EDF over the anticipated performance of its reactors over the coming months. Readers of past issues of Energy Highlights over the past 7 years will recall periodic references to the problem of France’s ageing nuclear fleet, currently supplying a mammoth 60 GW across Europe. Not only are nearly all 56 of France’s reactors of identical design, but many were also built at roughly the same time during or close to the decade of the 1980s. Most of them are now operating at or – in most cases – beyond their original design lives. With a far greater propensity now for things to go wrong or for preclusive reactor closures, shutdowns or emergency maintenance to hut supply unexpectedly. Amid the market turmoil elsewhere, it is not hard to see how warnings concerning reactor availability by the operator itself will have rattled the O.T.C. market in the way that they have. January is trading well north of £300/MWh as we go to the wire – a far cry from the “£70/MWh to £90/MWh” price range for the Q4 or Q1 periods, to which perhaps too many traders had grown accustomed. From a pure mark-to-market perspective, selling electricity to retail or commercial customers at current commodity prices must rack up significant losses per customer, possibly excess of 15 p/kWh once operating expenses, inflation-indexed network charges and non-recoverable taxes & green levies are added to the commodity prices prevailing on the O.T.C. We will just have to wait & see how demand evolves, regional renewable power generation performs and geo-political events unfold as we move deeper into winter.
Annual contract prices continued to soar:
April Year 22 Gas is trading above 185 pence therm (compared to circa 35 p/th in early January and April Year 22 Electricity is trading over £170/MWh (versus circa £45/MWh). There is a general mood of panic prevailing because the new price range appears to be self-sustaining, certainly less transitory as some traders had assumed. It is clear that losses incurred now in selling energy to commercial and domestic customers will be substantial. So a poison chalice for energy utilities asked to accept new customers, at least for the time being. This will be explained in more detail in a New Year’s edition of Energy Vision.