+44 (0) 203 916 0101 enquiries@holtenergyadvisors.com

Marginal Pricing of Energy - Who loses if liberalised markets don't ensure a sustainable equilibrium?

Marginal Pricing of Energy - Who loses if liberalised markets don't ensure a sustainable equilibrium?
Marginal Pricing of Energy - Who loses if liberalised markets don't ensure a sustainable equilibrium?

The volatility in the energy markets over the past three years firstly through the COVID-19 pandemic and more recently due to the war in Ukraine has served to demonstrate the importance of ensuring governments, energy companies and end users give consideration to all aspects of the energy trilemma. Throughout this period at least one party in the supply chain from energy production and generation through to end user (be it corporate, industrial, SME or residential) has been "on the ropes" when it comes to pricing, particularly in the European natural gas markets where the most volatility has been seen.

The security of supply, cost of energy and level of carbon emissions has long been a puzzle that energy companies, governments, NGOs and academics have sought to reconcile. Since the introduction of the NBP (National Balancing Point) natural gas hub in 1996, more and more natural gas has been purchased on this virtual trading hub at the "market" price breaking away from the historical negotiated prices for natural gas supply contracts which had existed pretty much since the development of North Sea natural gas.

For the first 10 years the NBP price hovered in a relatively narrow band of 15-40p/therm, likely driven by the fact a relatively significant proportion of pipeline gas (and nearly all early stage LNG) was still sold on a negotiated price with indexation (often to oil, substitute energies, inflation or a mix) rather than adopting the new NBP hub marginal cost pricing. Since 2005, volatility has markedly increased with the first warning of the effects of market based pricing coming in the winter of 2005 when prices first spiked above 100p/therm. The immediate reason for this was the predicted colder-than-average winter and the transition from net exporter of energy to net importer. Whilst a number of new infrastructure projects had been given the green light including new LNG terminals, UK-NL gas interconnector upgrades and new pipelines from Norway a lot of this new infrastructure was still 2+ years away.

The flip side of creating the NBP gas hub which had liberalised the market and provided an era of cheap gas saw price spikes in times of shortage with large industrial and commercial customers particularly hard hit. Industrial consumers argued that although the transparency and information asymmetry which had existed for decades had gone, it was replaced by essentially a wholesale mechanism of marginal pricing with the day-ahead price rising or falling by what was needed to attract the last molecule of natural gas needed regardless of the profitability (or not) of the 'average' production facility.

Fast-forward to 2020 during the pandemic and many North Sea gas producers were struggling financially with prices falling to as low as 5p/therm in mid-2020. International oil price indices including Brent and WTI dropped below $20/bbl leading to a large number of bankruptcies. In the USA around 50 exploration and production companies filed for Chapter 11 bankruptcies, along with over 60 oil-field service companies who rely on the producers to explore and drill for new hydrocarbon deposits. With new development projects requiring large capital investments and long-lead times, producers were looking to defer and extricate themselves from existing and incremental commitments. The hydrocarbon extraction sector is quite unique to other sectors in that the usual profile of extraction shows a decline in volumes recovered annually unlike say a car manufacturer whose plant production capacity can be maintained year-on-year. Oil and natural gas wells can often experience a 20% annual decline which makes them unique in that a disproportionately high share of the revenue and value of such projects is often extracted in the first 2-4 years even if the field may produce for 15 years. Develop a project when energy commodity prices are high (driving up the oil service sector costs and development costs) but start production when prices have dropped low and companies balance sheets can be easily destroyed.

Of course, the very lack of a balanced market equilibrium has led to the opposite effect that we are seeing in 2022. Oil and natural gas producers' production today was the result of investment decisions made two, five, maybe even ten years ago. Hence when the NBP price for December 2022 delivery hit over 700p/therm this August it seemed to all the very definition of a "windfall" had hit the producers. Surely this economic rent transfer made a windfall tax fully economically, politically and morally justified? Even the CEO of Shell suggested in October that governments may need to tax energy companies to fund efforts to protect the poorest from soaring bills.

The UK introduced its windfall tax the "Energy Profits Levy" back in July with HM Treasury stating it aims to raise £5bn in 2022/23. This was a substantial hike of 20% on an industry already paying a higher tax rate of 40% (compared to other firms who pay the standard rate of corporation tax of 19%) but still left North Sea producers with record profits estimated by one leading industry consultant of £46bn in 2022 with the prior 10-year average up to 2021 closer to around £6bn leading to the curious scenario of the Shell-CEO appearing more realistic about how the tax may need to evolve than some members of the previous Government.

So the solution is more tax on the oil and gas companies as that's where the transfer of value is going? This is only really a partial answer. The fact the impact of the Energy Profits Levy impact was dampened down by tax savings worth 91p of every £1 invested in fossil fuel extraction in the UK has led to companies again pushing to move exploration and development projects forward. Whilst the mechanics of the natural gas market and its marginal pricing (often being the marginal LNG (liquid natural gas) cargo needed to meet demand) means the price impact of new production may not be significant, the fact new gas volumes developed in the UK enhances our security of supply and also generates income for HM Treasury and jobs here means compared to importing high CO2 shipped LNG gas this strategy makes sense.

The North Sea Transition Authority (previously the Oil and Gas Authority) has recently opened a new licencing round in order to encourage more domestic production. This policy is being openly challenged by environmental groups and even the Labour party who have pledged not to conduct further licensing rounds. It is clear there will need to come a point where we stop hydrocarbon extraction but unless as a global population we are prepared to cut energy usage or pay even higher prices in the short term for intermittent renewables with capacity way below what is needed, hydrocarbons will need to play a role into the future - albeit mitigating to the maximum extent possible the impact on the environment. This is less about the oil industry self-preserving and more to do with the fact although renewables are ramping up and costs falling, this source of energy today is insufficient by some margin to meet global needs in terms of capacity or cost. Nascent technologies of CCUS and hydrogen should be encouraged and the oil industry certainly has the skills to help develop these technologies but right now there is still much to do to ensure they are economically viable at the scale needed. Being stuck without the oil and gas production capacity and infrastructure needed given the lead time involved risks repeating the mistakes made back in 2005.

With large amounts of Russian gas out of the system due to the war in the Ukraine, the current UK government and its predecessor administration have taken a completely different view on fracking as a way to assist with the energy trilemma. Not always well explained, but fracking is a technique used to extract natural gas and sometimes oil from tight rocks which otherwise would fail to flow at commercial rates. As a way of drilling and completing wells it is not new and is commonly used offshore and onshore in the USA. The difference to more "conventional" drilling is actually that its application onshore would allow us to tap into large natural gas deposits which are already proven due to the fact onshore the presence of shale gas (gas contained within what geologists call the source rock or essentially where it is initially generated) means almost certainty these gas volumes are present. Compared to offshore where source rocks are generally not targeted directly but, as they suggest, provide the source for hydrocarbons which may migrate to another location which can be accessed by drilling (reservoir rocks). The key difference of drilling into reservoir rocks compared to a source rock like shale is the probability of finding hydrocarbons is much lower, often with less than 30% "chance of success". Whilst drilling shale has the benefit of knowing natural gas is already present in many locations, it comes with two challenges which are less prevalent in the offshore. Can the gas be made to flow at commercial rates (which is where the fracking technology comes in) and will the local communities accept the use of the technology and industrial processes associated with extraction of gas from the shale? Fracking (or fracture stimulation) is to an extent like any other industrial process - if it is done correctly and as seen in the USA, it is proven to be safe. But like a chemical factory, refinery or nuclear plant there are risks which need to be managed and mitigated in order to complete operations safely.

The oil and gas producers are often seen as needing to generate higher equity returns for their shareholders (pension funds, insurance companies and private individuals) than other sectors due the inherent riskiness of their business. They take price risks which we have seen to be incredibly volatile as well as the geological (technical) risk of finding oil and gas deposits together with increasing political risk not least in terms of the longer-term transition to a cleaner economy. The majors and supermajors and even the larger independent oil companies are well placed financially due to their strong balance sheets and cash generation as well as technologically where they have robust processes to manage complex engineering challenges. The smaller oil and gas companies which have often been the most entrepreneurial in seeking new areas to explore and develop both in the UK and internationally are probably less well placed to adapt to a new green economy but have the benefit due to their smaller size and the fact most of their shareholders are focussed more on capital growth than dividend income, that they don't have to find new projects on such a large scale to replace billions of pounds of cash flow unlike the larger competitors.

The evolution of renewable technology has been relentless over the last decade particularly in wind and solar, the former of which the UK has become a global leader in the offshore. Back in early October, which seems a lifetime in politics, the UK government was working on laws which would impose a revenue cap on renewables generators after reports of plans to create a voluntary long term strike price appeared to fail. Like with LNG becoming the marginal supply source for natural gas and driving the wholesale price, natural gas itself is the fuel which is key for setting the wholesale electricity price given the key role it plays in producing over 45% of electricity in the UK. Yet solar and wind developers and other non-gas electricity generators receive the same price for their output but do not have the same cost of input given they have no exposure to the cost of natural gas. Industry and officials met during September with a price of £50-60 per megawatt-hour mentioned as reasonable cap. However, the two sides failed to find an agreement on what would be a voluntary opt-in to long term CFDs for existing generation projects. The EU has recently introduced a €180/MWh cap. Given that oil and gas producers essentially have no guaranteed floor price unlike many of the renewables providers, it seems logical the UK government will continue to press the case for a ceiling in order to protect business and residential consumers.

So what does this all mean for the energy sector? The recent reopening of the Rough gas storage facility (which can hold around 9 days of UK gas supply when fully operational) is a start. Although operating at only 20% capacity it increases total UK gas storage in the UK by about 50%. Peak-shaving supply will be helpful in taking some of the extreme spikes in prices out of the market but we will continue to be reliant on LNG where unlike with fixed pipelines, we will be competing internationally for supply. During 2022, we have taken cargoes from long-term suppliers like Qatar as well as the USA and even Peru. In the last month however, with storage facilities across Europe pretty full ahead of winter at around 95%, up to 30 cargoes (2.1 million tonnes) of LNG have been at sea around the Mediterranean and East Atlantic due for delivery at the end of October or early November for cargoes that were based on bookings in early September. As most regas terminals have little storage capability volumes will have to be sold into the day-ahead market which combined with the early November warm weather could see a significant drop in gas prices.

Since the spike in gas prices earlier in the year, around 30 energy supply companies have failed, many of which were relatively small and had been encouraged into the market to challenge the Big Six. Ofgem operates the Supplier of Last Resort (SoLR) process, so no households have had disruption to their supply, but the failure of so many energy suppliers has caused significant disruption to the market and raises many questions about the whole regulatory and pricing structure of the energy markets as well as the insolvency process in the energy sector. Ofgem's latest estimate of the total costs of supplier failures was £2.7bn with end consumers ultimately paying the cost. Whilst market liberalisation has brought a lot of positives in terms of competition and transparency, the idea that markets set prices effectively and efficiently to ensure equilibrium appears only partially true here. Over the past 2 years we have seen extreme financial pressure put onto oil companies, energy suppliers and consumers at one point or another. Whilst market intervention doesn't necessarily help to resolve the kind of rapid supply shortages we have seen due to the war in Ukraine, the last two years have showed us significant market failure exists and significant consideration needs to be given about how energy is bought and sold in the future to ensure viability for all market participants as the world seeks the long term challenge to get to Net Zero.

This article first appeared in INSOL World Journal Q4-22.
Visit www.insol.org