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WHOLESALE ENERGY PRICES: JANUARY – FEBRUARY 2020

In this article, Dominic Whittome covers recent changes to wholesale energy prices.

Crude Oil

Oil fell 15% over the last two months to just over $50/bl. The Forward Market for crude generally has lost a third of its value since the end of last summer. Today there is little doubt that markets are still spooked by the indeterminate spread of Covid-19 and the prospect of a sustained shutdown which may cut medium-term consumption of petroleum products worldwide. Whilst a demand downturn is already very apparent in South East Asia at least, the longer term demand prospects are much less clear. On the supply side, the signals would otherwise be quite bullish for oil prices. Lost in the fog of recent coronavirus events, exports from major OPEC producers have faltered. The region’s security of supply situation looks set to remain fragile amid worsening civil turmoil and increased terrorist activity in several key oil exporting countries. Such unrest is thwarting desperately-needed export infrastructure redevelopment in OPEC states such as Iraq and is actually impending exports of oil itself in others; the total volume exported out of Libya during this January was zero for example.

With the world’s population set to grow 2 billion between now and 2035, much of it within the North African and Middle Eastern region itself (the population of Egypt alone surpassed 100 million in February) and with more of OPEC’s oil output set to be consumed internally, it might be a mistake to bank on oil prices re-establishing themselves at the current $50/bl for long in spite of ‘carbon neutral’ efforts said to be made in some western economies.

Natural Gas

The Forward Year gas contract has now fallen some 40% since 1st January. Wholesale prices fell across the global market, hit by surplus LNG cargoes (unwanted by Asian buyers). Also European gas inventories are reported to remain stubbornly high just as we head into spring. Gas prices are actually now, in real terms, than they were after the UK gas market was liberalised in the early 1990s (under the infamous 90/10 Rule’ which obliged British Gas to sell 10% of its pre-contracted North Sea gas to establish the spot market we have today and below the Heren Index price in real terms, the bell-weather index as first reported in 1995.

However, there is no actual ‘security of supply’ concern in relation to gas. This commodity has an established and robust export network bringing long-term contract and spot supplies to Europe through well-maintained North Sea, Dutch, Russian, Algerian and LNG infrastructure routes. From a reserves perspective too, the gas supply outlook seems stable enough, with well over 250 years worth of forward supply cover, according to the reserves to production ratio published in the most recent BP 2019 Statistical Review. That said, unlike the case of oil whose reserves are held by various states and multi-nationals, over 75% of the world’s reserves of gas remain in the hands of two corporations: Gazprom Neft of Russia and NIOC of Iran. So looking long term, it will be important to consider both commodities through geo-political frames.  

Electricity

Base-load power prices continued sliding and the April Year 2020 contract fell another 25% to close at roughly £45/MWh. In real terms, power prices are only marginally higher now than they were in 1999 when the New Electricity Trading Arrangements (NETA) came into play. Most recently, the electricity price almost halved since the end-of-summer peak recorded on 1st October, 2019. But there has been no actual ‘step change’ in the UK supply or demand outlooks since then. There has been no positive news in respect of new-build gas or nuclear power stations. Both of which the UK must rely on, with all coal units now to come offline by 2023, one year sooner than originally planned. Sobering perhaps to recall in 1990 UK coal accounted for 71% of national power generation, compared with 2½% today. Question marks still remain over any commissioning date for the European Pressurised-water Reactor (EPR 1 design) at 3,200 MW Hinkley Point being built by investors EDF (56%), British Gas’s owner, Centrica (14%) and CNG of China (30%). No EPR1 has actually finished construction; the other two, in Finland and in France, have also been hit by delays. Hinkley’s investors secured a contract-for-difference (CFD) strike price (the CFD to be added to consumer bills) of circa £125/MWh in today’s money (under indexation terms for the headline £92.50/MWh Strike Price agreed in 2012). If we assume this new nuclear plant is commissioned and operates at 90% load, we can roughly predict the subsidy that will be added to domestic & business electricity bills over the 30 year CFD contract term. So the subsidy to be added to bills alone should amount to 0.9 x 3,200 MW x (£125 – £45) MWh x 24 x 365 x 30 = £60 billion circa in today’s money. This does imply rising power costs soon; also in the future considering the equivalent of 13 such-sized power stations will be needed to meet the UK’s expected 42 GW demand call by 2050. This one 3.2 GW nuclear plant will barely meet 7% of that quotient.

In January, the same consortium bar Centrica asked the government to underwrite a second, same design EPR1 reactor Sizewell under an alternative RAB model (regulated asset base) to entail direct Treasury support, though no decision has been made yet. Whilst the lead-time, capital risk and construction costs are far less for equivalent sized thermal power stations, the outlook for gas-fired plants has, if anything, deteriorated recently with reports of even the very smallest (sub 5MW) gas flexing units encountering local or (visiting) opposition from eco groups and no government lead as to the role that new build gas-fired stations should play. Looking forward therefore the UK power market currently looks stuck between a rock and a hard place. As pointed out in past editions of Energy Highlights, interconnectors and renewables will not come close to reliably meeting this 42 GW demand call in front of us. So in spite of regulator Ofgem’s current Targeted Charging Review, which will reduce ability of end users to reduce Capacity charges through triad avoidance, Demand Side Response should still have a role to play in helping businesses to cut costs, be it on-site generation, battery storage, heat recovery and energy conservation, as well as load-shifting itself. These options along with energy purchasing strategies could each help to mitigate contract price-rises ahead, especially if we see any snap-back in commodity prices as well. For the time being however, prices across the board look like staying subdued by Corona-virus related uncertainties.   

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.

Prospect Law is a multi-disciplinary practice with specialist expertise in the energy and environmental  sectors with particular experience in the low carbon energy sector. The firm is made up of lawyers, engineers, surveyors and finance experts.

This article remains the copyright property of Prospect Law Ltd and Prospect Advisory Ltd and neither the article nor any part of it may be published or copied without the prior written permission of the directors of Prospect Law and Prospect Advisory.

This article is not intended to constitute legal or other professional advice and it should not be relied on in any way.

For more information or assistance with a particular query, please in the first instance contact Adam Mikula on 020 7947 5354 or by email on adm@prospectlaw.co.uk.

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WHOLESALE ENERGY PRICES: JULY – SEPTEMBER 2019

In this article, Dominic Whittome covers recent changes to wholesale energy prices.

Crude Oil

Brent prices soared in the aftermath of recent attacks on Saudi oil facilities. Spot prices saw their biggest one day increase since the start of the first Gulf War in 1991, only to give up all gains inside three days and close the quarter down 5% just below $60/bbl.

In such times, one might expect to see a higher risk-premium factored in prices, along the curve. However, this has not been the case. Indeed, the speed of the price reversal may reflect the market’s main pre-occupation, the global economic outlook, or equally a continuing shift towards ‘short-termism’, perhaps as a consequence of AI/robot trading and the exit of ‘liquidity providers’ issues discussed in the last issue.

Meanwhile, the Saudi oil ministry has warned that further attacks that do succeed in halting production significantly would lead to “$300/bbl oil”. That figure may look headlining grabbing, although the statement is perfectly serious.

Saudi Arabia may hold 18% of global oil reserves and provide just 12% in terms of consumption. However, its seven producing fields still make up circa 75% of the world’s marginal supply. No other producer can make the numbers stack up. In fact, the world’s reliance on this swing producer has not changed significantly, despite the emergence of shale and frontier oil production outside the Middle East, typically with much higher development costs. With no early rest-bite to troubles in the Persian Gulf in prospect, the oil market looks set to stay jumpy for the time being at least. 

Natural Gas

The gas market held firm, falling back just one per cent over the last quarter. The Forward Market took in its stride news of the accelerated retirement of Groningen in the Netherlands, by far Europe’s largest producing gas-field, as well as concerns that Russian exports will be cut amid the spat with Poland in the European Courts of Justice.

This ruled that exports through the OPAL pipeline must be halved, just as winter 2019/20 sets in. On the demand front, various meteo-office reports suggest that this winter could be a severe one for the UK and across Europe. Gas storage and heating oil inventories on the Continent are reported to be very high at the moment and this will explain the market’s reaction. However, April Year 2020 gas prices could rise significantly above the 50 p/th mark once again if demand goes on to exceed expectations.

On the home front, it was confirmed that all remaining UK coal units will shut permanently by 2024. Theoretically, any shortfall here could be offset by gas-fired generators. There are several stalled projects in the pipeline. However, even if (and a big ‘if’ at that) a government policy shift were to see a limited renaissance in gas-fired generation, the timelines suggest that the power market could still come under stress, long before any gas cavalry arrives on the scene. The generation market looks unlikely to be the engine for any step increase in future gas prices therefore. However, the Forward Market could still creep higher for a variety of other supply questions over trans- European supplies and North Sea infrastructure.   

Carbon prices, meanwhile, were fairly resilient, with the traded EUA contract heading back towards €25/tCO2. The nominal Spark Spread finished more or less unchanged at £17.50/MWh. This nominal profit margin may look promising. However, the spark spread reduces sharply once eco taxes, levies and limits are factored in.   

Electricity

Forward base-load prices finished the quarter almost unchanged. However, the Prompt Market was jolted higher by concerns over output at five principal nuclear units in France. These were temporarily but very suddenly closed under orders of the National Safety Authority. No other EU countries have meaningful nuclear development plans of their own and many will remain reliant on French nuclear exports to balance their systems.

However, France’s reactors are clearly showing their age now. Significantly, they are almost all of identical design and they were built fairly quickly after one another; part of a hitherto successful national security of supply programme initiated by President Giscard d’Estaing in the aftermath of the 1973/74 oil crisis and continued by President Mitterand. But the worry now is of safely or other technical shortcomings found in group of reactors which will manifest themselves at other plants before long. There is no obvious ‘Plan B’ if enough reactors do have to shut early because renewables alone will not make up the numbers. 

Meanwhile, design and construction problems are dogging the introduction of the next-generation European Pressurised Reactor (EPR). Just three EPRs are being built at the moment. All have experienced delays. Hinkley Point C being the latest to mark-up construction costs last month. This plant may now be delayed further although this is not confirmed officially.

With all nuclear plants bar Sellafield due to close during the next decade, the UK’s cushion of reliable peak-shaving capacity in the system might look precarious to some people. Wind power developments will continue and we saw some ‘record low’ strike prices in the last offshore auction, below £70/MWh in some cases. However, in volume terms the numbers are still small. The time horizons are also long and in other cases the final supply prices are somewhat higher than headline figures may suggest. Interconnectors with Iceland, Scandinavia and Continental Europe (albeit French nuclear or coal generation) may preclude part of any future ‘imbalance’ but possibly not all of this.

The ‘Climate Change Emergency’ environment may well be making it difficult for governments to sanction a general relaxation for gas-fired plant development. This may be needed to avoid repeats of the late summer incident when blackouts occurred after just one renewable project at Hornsea and a comparatively small, 650 MW gas station at Little Barford tripped at the same time, resulting in an intra-day price surge to £375/MWh at one point. The may or may no be an omen for the decade ahead of us. But in balance, the power market should still brace itself for bumpy times ahead.

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. 

Prospect Law is a multi-disciplinary practice with specialist expertise in the energy and environmental  sectors with particular experience in the low carbon energy sector. The firm is made up of lawyers, engineers, surveyors and finance experts.

This article remains the copyright property of Prospect Law Ltd and Prospect Advisory Ltd and neither the article nor any part of it may be published or copied without the prior written permission of the directors of Prospect Law and Prospect Advisory.

This article is not intended to constitute legal or other professional advice and it should not be relied on in any way. 

For more information or assistance with a particular query, please in the first instance contact Adam Mikula on 020 7947 5354 or by email on adm@prospectlaw.co.uk.

For a PDF of this blog click here

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WHOLESALE ENERGY PRICES: MARCH – JUNE 2019

Crude Oil

Having eclipsed the $70/bbl mark at one stage, the Brent contract fell back to finish the second quarter 8% down, as fears of an US-Iran war eased for at least for the time being. Nevertheless, the Persian Gulf remains a tinderbox, one which could cause crude oil prices, and petroleum product prices in particular, to snap upwards at some point. If recent history can tell us anything, perhaps it is that military campaigns in the Middle East can last longer and have far further-reaching consequences than initially imagined. So this latest stand-off with OPEC’s second highest oil producer in terms of proven reserves, could equally affect the forward markets for gas and electricity, not just prompt prices.

Natural Gas

In this context, Gazprom of Russia and NIOC (National Iranian Oil Company) together hold some 80% of global gas reserves which are economically-recoverable at current prices. Although no Iranian gas to speak of is exported to Europe in significant volumes, certainly not yet, conflict with the US could have all sorts of impacts across energy commodities markets.   

Leaving geo-political issues to one side, it may be worth looking at the supply & demand fundamentals. In particular, consensus industry estimates of the break-even (long-term marginal cost (LRMC)) of bringing new gas supplies to the European border over the next decade, as existing 25 year gas and LNG contracts (many signed in the late 1990s) expire.

One of many expressions bandied in trading circles is the one that “the market is well supplied”. By itself, this statement is perfectly true. The day-ahead market always clears after all. But it is not so much prompt market availability which affects wholesale or industrial gas prices. It is the ‘break-even cost’ (LMRC) of mobilising new gas supplies and bringing them to market.

The consensus industry estimates now put the LRMC for new gas supplies, those destined for North West Europe over 2020-2030, at between $8.00/MMBTU (for West African, Siberian and low-case North American shale) and $10.00/MMBTU (including Frontier LNG and high-case North American shale). Even were we to assume the lower-case eight dollar MMBTU figure and assume gas is delivered at or close to the break-even price (so no risk-premium and low supply margin), then at current exchange rates the UK wholesale gas price could still rise past 70 p/th, i.e. a third higher than today with the Annual Contract just closing the second quarter up 6% at 49 p/th.

So, notwithstanding Climate Change Emergencies and Zero Net Carbon 2050 targets set in Westminster, no demand side reduction or perceived ‘abundance’ will altar what the financials are suggesting: that gas prices may not fall far from here and even if they do it will not be for very long. No major producer will export at a loss. So, if our ‘cost plus’ valuation is accepted, then gas prices could start to rise as more legacy long-term contracts expire, replaced by higher-cost/ LMRC supplies.

For all its merits, renewable electricity does not offer reliable base-load supply. And it actually increases relative demand for peak-load generation. Given that all 14 operating reactors in the UK bar two at Sizewell will be decommissioned over the next ten years, today’s ca. 80 TWh demand call from gas-fired power stations looks very unlikely to fall. Indeed the share of gas in the UK’s generation mix may need to rise at some point. The combined domestic heating & industrial quotient for gas is much higher, at circa 250 TWh and there are measures to phase out use of gas in homes past 2025. However, this demand tail-off will be gradual. As the economics stand (and are unlikely to change) an impending deficit in flexible/peak-load electricity looks very plausible. Perhaps it can only be properly addressed by new forms of fossil generation, be it domestic gas-fired generation or brown- coal generation, imported from Poland or Germany through interconnectors. Either way, the consensus LMRC figures suggest in future, Forward Market gas prices will be higher.

Electricity

Base-load power prices followed natural gas, rising 5% over this last period April to July.  There was also the announcement that, for the first time in the UK’s industrial history, ‘clean electricity’ had exceeded fossil generation.

Amid the fanfare, it needs repeating that the Whitehall’s definition of clean electricity includes nuclear power. And while last month may have been a trailblazing one for renewables, the tail end of June saw day-ahead power prices spiking up to £375/MWh or 38 p/kWh. This was partly attributable to cloudy skies and low-wind speeds which severely cut renewable generation. More ominous perhaps (since such imports are being relied on more to fill any supply gap) was the wanting performance of Nordic and Northern Europe inter-connectors. The general reliability of such cables was discussed in recent editions of EH. In the event, it was domestic gas-fired generation that the system ultimately had to fall back upon on, come the day itself Monday 24th June.

This tale relates as much to nuclear power as it does to gas. The mainstream political parties remain opposed to any new-build gas programme and with no new-build nuclear reactors bar Hinckley on the horizon, the UK power market does appear to have a forward supply & demand picture that doesn’t stack up – or certainly the consensus in the Energy Highlight bunker just now. What this could mean is two fold. First, perhaps we should brace ourselves or hope for some change in government policy. Even it no change is announced any time soon and this can has been kicked many times before. Inter-connectors alone, even if/when the power supply is firm, will not compensate for GW output lost by retiring UK reactors. Second, it we assume there is no government money left for significant new subsidies and limited stomach either for new levies on households, then our energy authorities may well feel inclined to sit back, watch the market mechanism do its work and see wholesale power prices rise and so quell the energy demand to help the UK reach the new and somewhat fiercer ‘Zero Net Carbon’ emissions target announced last month.

Looking short term, power prices could rise if French, Benelux or German reactors shut due to lack of cooling water from reservoirs amid the European heat-wave. On the downside, renewables output is currently strong and across energy markets generally there are concerns over the global economy which may dampen both gas and electricity demand.

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. 

Prospect Law is a multi-disciplinary practice with specialist expertise in the energy and environmental  sectors with particular experience in the low carbon energy sector. The firm is made up of lawyers, engineers, surveyors and finance experts.

This article remains the copyright property of Prospect Law Ltd and Prospect Advisory Ltd and neither the article nor any part of it may be published or copied without the prior written permission of the directors of Prospect Law and Prospect Advisory.

This article is not intended to constitute legal or other professional advice and it should not be relied on in any way. 

For more information or assistance with a particular query, please in the first instance contact Adam Mikula on 020 7947 5354 or by email on adm@prospectlaw.co.uk.

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WHOLESALE ENERGY PRICES: JANUARY – FEBRUARY 2019

In this article, Dominic Whittome covers recent changes to wholesale energy prices.

Crude Oil

Dated Brent has risen some 25% in two months, in a crude market rattled by deepening geo-political tensions worldwide and continuing worries about medium-term supply from embargoed Venezuela. There are also concerns over Iran, which is subject to US sanctions, whilst there are threats of upheaval in Nigeria and Sudan.

New US sanctions and talk of military pressure to remove President Nicolás Maduro have contributed to oil production falling below 1 million barrels a day, down from circa 2.5 million barrels just four years ago.

Venezuela only recently overtook Saudi Arabia to become OPEC’s largest player in terms of proven reserves. A well publicised ‘re-newel of vows’ or closer military accord with Russia will only have stoked tensions further. While global petroleum prices have had a good run, they have potentially further to go, especially if we see investor flight into hard commodities. Dated Brent remains well below its most recent $85/bl peak in October last year.

Natural Gas

Short-term market changes and the geo-political situation may have caused a breakdown of gas price correlation to oil, with Forward Year prices down by eight per cent. Seasonal gas demand slipped back last month and the market has been well supplied to date.

Gas prices followed electricity down, for here the price convergence between these two commodities increased over the last year. On 1st Jan, 2018 forward gas prices stood at 46.60 p per therm, with electricity trading at £44.85/MWh versus 54.47 p and £56.18 today. One factor at play here is the carbon market. The second half of 2018 saw struggling nuclear output and renewable electricity both fuelling demand for fossil generation. This was chiefly offset by rising gas and coal-fired plant. Indeed fairly extensive new-build coal programmes are already underway in Poland and Germany.

In the short-term, elevating coal-fired plant further up the generation stack has served to increase demand for carbon permits. This contributed to soaring carbon prices on the EU Emissions Trading Scheme. In 2018, the prices of traded EUAs soared by over 400% at one point, from circa € 7.50/ tonne CO2 in January 2018 to current trading levels closer to €20. The carbon factor has increased the running cost of gas-fired plants in the UK, paradoxically undermining the economics of new-build plants which the country may need to maintain supply cover ahead, a point we can look at now.

Electricity

In January, Hitachi cancelled its planned 2,900 MW nuclear power station project destined for Wylfra in Wales from 2027, hot off the heels of Toshiba’s own aborted 3,400 MW project in Cumbria.

Given the very price swap/Contract-For-Difference subsidies involved, it is perhaps tempting to think that the termination or suspension of any more nuclear plants will alleviate the pressure on future prices. However, the reality is probably much more sobering, because the non-fossil alternatives may well prove equally or more expensive, certainly in the electricity volumes which may needed.

The Forward Market may well be even more reliant on potentially expensive imports via interconnectors. These entail an additional security of supply risk. Although the UK has a healthy-looking pipeline of new interconnector projects, the existence of new cables is no guarantee of supply.

The cross-Channel interconnectors, new 1 GW and 2 GW wires from Holland, Belgium, Denmark and the six espected from France may each be subject to competition from Continental buyers when it comes to peak demand days. Although Norwegian and Icelandic exports may be dedicated to the UK mainland, the technical issues will remain here too, with volumes being exported over longer distances and at very high voltages to minimise transmission losses. Sub-sea networks generally involve sophisticated equipment which can fail, even with state of the art technology. Hence, this is simply a new element of risk which the UK market may have to grapple with, together with competition for supply.

Taking a far-forward look at commercial power prices, it is worth considering the demand effects of government legislation. These became more apparent last month, with Whitehall confirming measures to phase out all domestic gas use, starting with new-build homes after 2024, on top of government targets set for electric vehicles. The numbers are still being crunched as we speak. However, our initial calculations suggest that to meet current Whitehall targets for domestic gas reduction and electric vehicle uptake by 2030, new supply volumes of 40 TWh/y and 160 TWh/y will be required, which could increase existing national demand to 520 TWh/y compared its 320 TWh/y level today.

In fact, any demand figure above 500 Terra Watt hours would look challenging given the current grid and generation constraints ahead. With all of the UK’s existing nuclear power stations bar Sizewell due to be retired well before then, it will be interesting to see how the government, grid companies and generators may work together to square this circle, without some shift in energy policy or without causing some consternation in the Forward Markets.

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. 

Prospect Law is a multi-disciplinary practice with specialist expertise in the energy and environmental  sectors with particular experience in the low carbon energy sector. The firm is made up of lawyers, engineers, surveyors and finance experts.

This article remains the copyright property of Prospect Law Ltd and Prospect Advisory Ltd and neither the article nor any part of it may be published or copied without the prior written permission of the directors of Prospect Law and Prospect Advisory.

This article is not intended to constitute legal or other professional advice and it should not be relied on in any way. 

For more information or assistance with a particular query, please in the first instance contact Adam Mikula on 020 7947 5354 or by email on adm@prospectlaw.co.uk.

For a PDF of this blog click here

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WHOLESALE ENERGY PRICES: OCTOBER 2018

In this article, Dominic Whittome covers recent changes to wholesale energy prices.

Oil

Despite the efforts of the US to almost brow-beat Saudi Arabia into increasing output, crude oil continued to march upwards and rose a further 9% amid open talk in trading circles of a possible three digit oil price at some point this winter, especially if crude or petroleum product inventories look like tightening further.

Paradoxically the latest intervention will have made the Saudis even less inclined to raise output, lest it reinforce the perception it is know-towing the US and working at odds with its cartel partners. There are other reasons why high prices (though below $100/bl) remain a policy goal for the kingdom, not least the delayed floatation of Aramco, for which a robust oil market remains essential.

There are also physical limits as to how much more oil it can produce. No OPEC oil producer should ever want its geo-politically priceless ‘swing capacity’ put to the test unless absolutely necessary. The same holds true for many North African and South American oil producers who may be strong on reserves but still have quite limited capacity to export more oil amid creaking infrastructure and worsening economic outlooks that will thwart foreign investment.

With the Russians and Iranians incentivised to rattle the cages of Western economies, this winter could see further stockpiling that alone will cause the market to tighten. The petro-dollar meanwhile has strengthened through the year, magnifying energy inflation effects in many oil importing countries. Indeed, inflation is a key factor to watch for general energy consumers, with rises in petroleum product prices evidently feeding to gas and liquid fuel markets with contract prices fixed against oil and escalation terms indexed to oil in a stronger petrodollar.

Gas

Natural gas prices increased another 12%, following on from their 15% climb over the May and June period amid expectations of continuingly high crude prices and a cold and protracted European winter that might extend into the shoulder months of March and April, when the Forward Market is generally at its most volatile and gas storage close to depletion in some regions.

In particular, the UK is now without a major gas storage facility following the closure of Centrica’s Rough platform. Whilst concerns over the security of supply from Russia and other Eastern countries may have been overstated in the past year, the forward market is probably now building, amid clearly rising East-West tensions, a higher risk-premium into prices out on the curve. Last month the UK’s annual gas contract hit a ten year high, breaking past 70 pence per therm at one stage.

However, today sees gas prices being influenced by an ever-expanding mixture of global supply & demand factors, with LNG playing a marginal supply role, including recent hurricanes in the USA which drove up crude and spot gas prices up in tandem. In fact, there has been no shortage of bullish news to keep the prompt market strong and this is now affecting gas prices further out on the curve, even if the actual justification for rising long-term gas prices is tenuous. Indeed from a resource perspective there is no actual or expected shortage of gas. The commodity enjoys an increasingly wide geographical spread as far as production is concerned and, according to the latest BP figures, the world has well over 300 years of forward supply at current rates of consumption. In reality however, short-term security of supply concerns, together with persisting long-term indexation to oil, have served to keep driving gas prices higher. The NBP traded over-the-counter price for gas has since risen by over 75% in the last eighteen months.            

Electricity

Although it had been hoped that most of Europe’s reactors would be back up after the summer hiatus, when a lack of cooling water supplies forced many to go offline, there have been reports of persisting outages. The age of nuclear fleets across the Continent is now a growing concern. In the UK too, all existing nuclear power stations, bar Sellafield, are due to close within five to ten years.

It is also becoming clear that renewable electricity and sub-sea interconnectors will not plug the gap, with new-build reactor projects arriving late, due to construction and safety problems, or not even getting off the ground at all amid concerns over technology, rising costs and funding.

In the backdrop, several European countries are quietly permitting the building of new fossil-fuelled power stations. Germany is currently installing coal-fired plants at a faster rate than the Chinese and last month it sanctioned the felling of an entire tree forest to produce the lignite dedicated to power generation.

The UK government itself has just given the go-ahead for a mammoth 2,500 MW gas-fired power station at Eggborough, the site of a former coal-fired plant that was closed only recently. This new power plant will produce some 80% of the output of Hinckley Point C; it will come on line sooner and it will not entail any meaningful subsidy, not from government or from the consumer by way of price-support under CFD tariffs added to bills.

Whether or not these examples mark a general policy shift towards fossil-fired generation remains to be seen. In the meantime, however, the market is tightening.                                                                                                                                 
About the Author

Prospect Law is a multi-disciplinary practice with specialist expertise in the energy and environmental sectors with particular experience in the low carbon energy sector. The firm is made up of lawyers, engineers, surveyors and finance experts.

This article remains the copyright property of Prospect Law and Prospect Advisory and neither the article nor any part of it may be published or copied without the prior written permission of the directors of Prospect Law and Prospect Advisory.

Prices quoted are indicative and may be based on approximate or readjusted prices, indices or mean levels discussed in the market. No warranty is given to the accuracy of any view, statement or price information made here which readers must verify.

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.

For more information or assistance with a particular query, please in the first instance contact Adam Mikula on 020 7947 5354 or by email on adm@prospectlaw.co.uk.

For a PDF of this blog click here

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BIGGER BILLS WILL DRIVE BATTERY INVESTMENTS BEHIND THE METER

Rising non-commodity costs and resilience concerns make batteries more attractive for big users.

Increased Charges

Energy is pure expenditure. There is no investment or “hidden benefit” to be had, and even for companies that can damp down usage, there are bill increases to come. Prometheus Energy, a demand side response and reserve battery provider, reported in 2017 that more than one UK business in 20 incurred financial losses due to at least one brown or black-out last year.

The wholesale market aside, business prices will rise because of increases in network capacity charges and higher levies. As of this April there are seven separate taxes, on top of commodity and capacity costs. My research suggests that capacity and tax rises will have increased a typical commercial user’s bill by 35% between October 2017 and September 2020, even with no increase in wholesale prices.

Even if wholesale prices stay fixed for three years, many bills will rise 32% because of network capacity and government surcharges. By 2020, the commodity cost will make up just a quarter of the bill.

Seeking a favourable energy quote will still help. However, competitive tendering alone will not protect businesses from the changes ahead. However, there are measures users can take, some quite easy, to reduce these charges or avoid them altogether.

Mitigating Increased Charges                                                                                                                                                                                                                                                                                                                                            Top of the list is responding to Triad warnings. High usage during a Triad period (declared by National Grid months after the event) can increase transmission charges substantially, with the user effectively “recategorised” and positioned in a higher pricing charging band that may apply to all future consumption.

Second is responding to distribution charges, which are influenced by consumption in Red Zone periods. Unlike Triads, Red Zones occur at known times. These have generally been weekdays from 4pm to 7pm, but it varies between networks and by location, and the timing of those zones may change.

Over-the-Counter Trade Registration

Larger consumers may consider a managed OTR service (over-the-counter trade registration). This offers a combined trade sleeve and clearing service, and can streamline trading through one channel.

It can also cut energy costs, firstly because it gives a company direct access to the OTC (over-the-counter) market, which removes various visible commissions, transaction costs and hidden commissions, premiums and bid-offer spreads. Secondly, it means access to the entire wholesale market, because an OTR vehicle can simultaneously access every player in the power market, access all bid-offer pairs that have been posted and thus buy or sell at the most favourable price available.

Finally, a managed OTR service can spare the expense of signing up to the Balancing and Settlements Code (BSC) or other legal-intensive agreements, with every BSC-accredited player that the client wishes to trade with. The managed OTR service can be a low-cost way to start trading on the wholesale market directly, and can mitigate many operational costs and risks associated with trading with Elexon (National Grid) as principal and also with GTMA players directly.

Battery Hosting

With those bases covered, energy buyers will be looking at a combination of competitive tendering and more active demand-side management, including the possible application of demand-side response (DSR) hardware and DSR-related battery storage. It may be cost-effective to install on-site generation and a battery in unison. As with energy service contracts, battery hosting contracts are likely to become more familiar. Hosting a battery would mean a battery service specialist will supply, operate and maintain the battery system in exchange for a share of the annual saving from the “host” company.

A battery has side benefits as well. It offers some emergency power, automatic brown-out protection and limited blackout protection. It will also automatically improve power quality – valuable for businesses that can be disrupted by voltage surges, harmonic distortions and other network issues. Broader benefits and lower energy bills are likely to combine to ensure battery installation remains the flavour of the month for many months to come.

About the Author

Prospect Law is a multi-disciplinary practice with specialist expertise in the energy and environmental sectors with particular experience in the low carbon energy sector. The firm is made up of lawyers, engineers, surveyors and finance experts.

This article remains the copyright property of Prospect Law and Prospect Advisory and neither the article nor any part of it may be published or copied without the prior written permission of the directors of Prospect Law and Prospect Advisory. 

Prices quoted are indicative and may be based on approximate or readjusted prices, indices or mean levels discussed in the market. No warranty is given to the accuracy of any view, statement or price information made here which readers must verify.

 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. 

For more information or assistance with a particular query, please in the first instance contact Adam Mikula on 020 7947 5354 or by email on adm@prospectlaw.co.uk.

For a PDF of this blog click here

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WHOLESALE ENERGY PRICES: MAY – JUNE 2018

In this article, Dominic Whittome covers recent changes to wholesale energy prices.

Oil

Despite reports of US influence, and of OPEC agreeing a relaxation in quota to offset supply problems from Venezuela and sanctions on Iran, crude prices extended their gains to end the period 11% higher.

This output increase is essentially a token gesture anyway, given that most OPEC and non-OPEC countries are already producing at or close to capacity whilst the global supply cushion stands below 4%, the lowest it’s been for 30 years. Consequently, Vienna’s meeting of minsters has done little to reverse the price trend. However, the recent levels also raise questions about the authenticity of the ‘shale oil’ argument.

It was barely two years ago when investment banks were issuing research papers declaring ‘$30 – $40 /bbl – the new norm’ amid expectations of fracked oil and gas keeping the world over supplied. As things turned out, oil prices doubled and many forecasts were promptly re-written. Perhaps a reasonable question to ask is that if there is (or ever was) close to this amount of surplus shale, then why are prices this high now, despite the actions or inactions of OPEC producers?

Prices might soften over the coming months but they are very unlikely indeed to return to anywhere close to the levels discussed in the market barely two years ago. Meanwhile, rising world inflation, which will add to transport, production costs and enhanced recovery budgets, could also drive oil prices higher, whilst the talk of US fiscal tightening and the strong petro-dollar have taken some of the sting out of oil price rises in nominal/dollar terms. Any relapse though, or renewed money printing that sees the dollar fall, could repeat the surge in oil prices last seen in the aftermath of the First Financial Crisis, which witnessed a flight into safe assets, hard commodities, including oil, that then dragged the market above $80/bl when demand was actually weaker than now. The forward outlook therefore appears stable and the current ‘high prices’ environment may be with us for a while.

Gas

Forward gas prices climbed a further 15% amid an unreasonably strong prompt market, with even spot prices trading over 50 p /th and sharply rising petroleum product prices. Oil prices themselves last fell below $40/bbl in April 2016, although their main assent (from $ 45 to $ 75) took place within the past 15 months. This timing may be significant and it may partly explain why wholesale gas prices are rising as fast as they are now.  The ‘low’ gas prices in 2016/17 are due to fall completely out of most long-term contract price escalation formulae soon, if not already. There will therefore be a contractual readjustment for gas via key take-or-pay Russian, Norwegian and LNG gas contracts, most of which account for marginal supply and will dictate forward prices as we move into the next buying round or into the next Gas Year on 1st October.

The OTC market has also seen carbon prices soaring. Today the EUA is trading above € 15/ tonne CO2 versus € 5/tonne CO2 exactly a year ago. While a sharply higher carbon price might be expected to depress gas demand, its overall (and certainly more immediate) effect will be to increase the principal feedstock price for gas generators. Events in the EU ETS will therefore be doing nothing to support any renaissance in new-build gas-fired generators, which may well be needed before long as the national generation margin shrinks further.

Electricity

Forward power prices surged 13% over the period. However, with the medium-term outlook for gas and most other indigenous power generation looking fairly soft, the grid will be relying increasingly on new interconnector imports from the Continent, Norway and potentially Iceland further down the line.

As previous articles have commented, this energy strategy may be unsound, not so much for ‘import/export’ reasons per se but basic reliability. Leaving to one side the question of plant reliability and ability or willingness of European suppliers to offer peak power when needed, the reliability of sub-sea cables needs to be considered as such systems are themselves prone to outages, even the newest cables with the latest electrical technology.

However, with the Hinkley Point power station (which when ready will barely supply 5% of the market) unlikely to produce at capacity before 2025, and other nuclear plants also delayed and unlikely to come online until ca. 2030, the short-term and medium-term generation outlooks are tight. However, rather than higher wholesale prices, the impact will be expressed in sharp rises in premiums and the cost of shape in end-users’ commodity prices, i.e. on top of capacity price increases and increasing eco levies and taxes (now seven in total).

The recent changes discussed above suggest that, if anything, the average businesses will now see power bills rising by 40 – 45% (the top end of the range estimate) within just three years. This prospect should spur end-users to look at energy reduction, demand-side management, on-site generation and profile-correcting batteries.

Prospect Law is a multi-disciplinary practice with specialist expertise in the energy and environmental sectors with particular experience in the low carbon energy sector. The firm is made up of lawyers, engineers, surveyors and finance experts. 

This article remains the copyright property of Prospect Law and Prospect Advisory and neither the article nor any part of it may be published or copied without the prior written permission of the directors of Prospect Law and Prospect Advisory.

Prices quoted are indicative and may be based on approximate or readjusted prices, indices or mean levels discussed in the market. No warranty is given to the accuracy of any view, statement or price information made here which readers must verify.

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. 

For more information or assistance with a particular query, please in the first instance contact Adam Mikula on 020 7947 5354 or by email on adm@prospectlaw.co.uk.

For a PDF of this blog click here

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WHOLESALE ENERGY PRICES: MARCH – MAY 2018

In this article, Dominic Whittome covers recent changes to wholesale energy prices.

Oil

Crude prices crept up a further 4% up amid renewed concern over OPEC exports, the possibility of new US oil sanctions on Iran and reports Houthi rebels starting to target Saudi exports of crude – a possible long-term campaign with the insurgency in Yemen showing no sign of abating.  Exports from OPEC’s second largest producer, Venezuela, were hit by a wave of national strikes and the market was buoyed further by the prospect that OPEC and non-OPEC countries agreeing to prolong their Accord and roll forward their production cuts well into next year. There are perhaps sound, if nefarious, incentives for Russia to take a lead in oil production sacrifices, possibly to ‘rattle the inflation cage’ of certain Western economies. Saudi Arabia will also be keen to keep oil prices as high as possible, in preparation for the partial sale of Aramco, whose stock market float is still believed to be on the cards. All in all, there have been few reasons to short crude over the past two months and oil prices could well strengthen further as we move into summer.

Gas

With oil prices re-visiting highs not seen in four years and heading for $70/bl, the effect of lagged oil price indexation in Trans-European take-or-pay gas contracts will be growing as the new gas year approaches on 1st October. Significantly, there are several major long-term contracts coming up for renewal. The starting Base Price in such deals will also be up rated and a ‘ratchet effect’ may be reflected to some degree in the Forward Market itself. Annual NBP gas prices rose a further 5% during the two month period. Despite the relative abundance of physical gas and the prospect of spot LNG cargoes being released by South East Asian buyers, gas prices could rise further if petroleum markets continue to climb as they have been.

Electricity

Prices rose 13% following the oil and gas higher (both more liquid and actively traded) although the market was spooked by the shutdown of the Hunterston B reactor. Although the plant was soon back online, the episode served as a reminder of the state of Britain’s aging fleet of Advanced Gas-cooled Reactors. All AGRs are set to operate well beyond their original design lives and this design accounts for all still-functioning reactors bar Sellafield. EDF was confirmed in one report to have said “the findings [at Hunterston] will probably limit the lifetime for the current generation of AGRs” so some nuclear output may come off line sooner than expected and before new-build reactors can replenish it. This long-term outlook was dimmed further by reports of defects identified in rivets forged for the EDF’s two European Pressurised-water Reactors (EFRs) under construction in France and Finland. The concern being that such design faults may extend delays at its third EPR under construction at Hinkley Point.

Wholesale market aside, business prices are set to rise anyway due to legislated increases in network capacity charges and higher tax levies. As of this April there are now seven separate taxes, on top of commodity and capacity costs. My research suggests that capacity and tax rises will have increased a typical commercial user’s bill by 35% over the period Oct 2017 to Sept 2020, i.e. assuming as a baseline we see no rise in the wholesale prices (in Oct 2017 £45/MWh or 4½p/kWh, so already up 14% since) . Energy buyers will possibly be looking at a combination of competitive tendering and more active demand-side management, including the possible application of Demand Side Response hardware and DSR-related Battery Storage, a topic to feature in Energy Focus soon.

Prospect Law is a multi-disciplinary practice with specialist expertise in the energy and environmental sectors with particular experience in the low carbon energy sector. The firm is made up of lawyers, engineers, surveyors and finance experts.

This article remains the copyright property of Prospect Law and Prospect Advisory and neither the article nor any part of it may be published or copied without the prior written permission of the directors of Prospect Law and Prospect Advisory.

Prices quoted are indicative and may be based on approximate or readjusted prices, indices or mean levels discussed in the market. No warranty is given to the accuracy of any view, statement or price information made here which readers must verify.

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. 

For more information or assistance with a particular query, please in the first instance contact Adam Mikula on 020 7947 5354 or by email on adm@prospectlaw.co.uk.

For a PDF of this blog click here

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WHOLESALE ENERGY PRICES: JANUARY – MARCH 2018:

In this article, Dominic Whittome covers recent changes to wholesale energy prices.

Crude Oil

Crude prices paused for a breather amid confirmation of a surge in North American exports of shale.

US oil production broke through the symbolic 10 m/bd, the first double-digit figure since the early 1990s.  However, this headline event did little to knock the crude market, with prices remaining flat over the period. Its impact was tempered by a rise in compliance levels across other oil producing countries in respect of Wider OPEC’s November 2016 Accord with OPEC itself, exporting 32.25 mb/d which is a ten-month low. The oil market is also being underpinned by heightened geopolitical concerns which are now, if anything, more heightened then they were last year. The final success of the ‘anti-dissident’ crackdown and purge in Saudi Arabia remains far from clear. There seems to be no consensus among analysts and observers as to when or how the ‘end game’ (which is not clear either) will play out or how robust any favourable  outcome will be.

Any flare-up or renewed uncertainty in this respect will immediately rekindle prices. Although, the medium-term oil supply outlook remains comparatively stable otherwise, at least for the time being.

Natural Gas

The gas market saw the curve rising just 1%. Although, spot  prices charged above one pound a therm at one point amid a conflagration of adverse factors all coming together at once. These included import problems at the Nyhamna Gas Terminal Plant serving Langerled pipeline to the UK;  technical issues with Dutch export Balgzand Bacton pipeline itself; a spike in energy demand throughout the North West European corridor amid freezing weather conditions and some market nerves heightened perhaps by enforced N Grid gas curtailments (if only temporary) and an appreciation that the UK finds itself in its first winter without any long-duration gas reserve facility of its own to fall back on.

This follows the closure of Centrica’s Rough offshore storage platform, as discussed in January’s edition of Energy Highlights. Overall, however, the forward gas market looks well-supplied in the medium-term, notably in respect of LNG supplies. That said, the UK’s own long-term import dependency is set to rise, past 90% by 2040 according to the latest National Grid research. Forward gas demand may well be curbed by government legislation restricting domestic gas and space heating use into the next decade.  Moreover, an early demand-call from the power generation sector also looks unlikely. Carbon prices meanwhile rose by over 80% over the past nine months, breaking €10/tonne CO2 at one point.

The unfavourable regulatory outlook for new-build gas-fired power stations could keep a lid on prices. Although government policy could always change; indeed the treatment of specific gas-fired generation is known to be under review in Whitehall circles, even if the question is seldom aired very publicly.

Electricity

Despite the cold snap, the electricity market slipped back. The annual base-load power contract fell by 7%  on the back of improving plant availability and very few reported outages during a critical demand period.

That said, the current state of the wholesale electricity market perhaps belies the impacts pending on prices downstream. In particular, on smaller industrial and commercial customers who have no exemption from the new (somewhat paradoxically-named) ‘Energy Intensive Industries Exemption Surcharge (or EII) that comes into effect in Q2.

The EII will not be introduced as a tax in name, although that is precisely what it is. The EII will instead be introduced as an ‘uplift’ to existing surcharges, namely the Renewables Obligation, absorbing circa 60% of the new levy; the Feed-in-Tariff and the Contract for Difference surcharges, absorbing circa ca. 20% a piece. Most of the energy intensive users’ exemption surcharge will fall on the non-energy intensive users  with no exemption from this (once conceived) ‘carbon tax’. This, combined with other increases in transmission and distribution network charges, as already penned and indexed to inflation, will cause the median commercial electricity bill to rise by circa 25% in just three years from now, according to provisional calculations (my own – happy to compare notes with any reader on that question).

This expected rise in bills also assumes no rise at all in wholesale power prices between now and 2022, which is far from a given. Enhanced efficiency, optimised energy management, embedded generation and possibly electric storage may become more commercial as a consequence, as end users look for ways to side-step potentially significant future price rises.

This article remains the copyright property of Prospect Law and Prospect Advisory and neither the article nor any part of it may be published or copied without the prior written permission of the directors of Prospect Law and Prospect Advisory.

Prices quoted are indicative and may be based on approximate or readjusted prices, indices or mean levels discussed in the market. No warranty is given to the accuracy of any view, statement or price information made here which readers must verify.

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. 

For more information please contact us on 020 7947 5354 or by email on: info@prospectlaw.co.uk.

For a PDF of this blog click here

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WHOLESALE ENERGY PRICES: NOVEMBER – DECEMBER 2017:

In this article, Dominic Whittome covers recent changes to wholesale energy prices.

Oil

The petroleum market continued to charge upwards. Dated Brent prices closed the two month period 19% higher. In the last two years, since the January 2016 Edition of Energy Highlights, world oil prices have risen over 80%. Whilst the so-far successful accord between OPEC and non-OPEC producers has certainly had an impact, shale has yet to have the dampening effect which some in the market had asserted it would.

No one knows how far oil prices may have to run before marginal supplies (i.e. not covered by the Accord, US shale being just one option available) arrive en masse. Whilst prices will not necessarily reach this level, E&P studies suggest that only once oil prices are sustained over $75/bl will significant new developments come online.

The Brent market spiked higher in December amid outages at Statoil’s Troll platform and Forties pipeline, which shut-in over 70 North Sea platforms in total at one stage, including the ETAP, Armada and Buzzard fields along with Forties itself, removing 45% of UK winter supply. While the pipeline is back online now, attention at the turn of the New Year turned towards troubles in Iran, which buoyed Dated Brent cargoes above $65 /bl into the New Year.

Natural Gas

Natural gas prices, on the other hand, took most of last month’s events in their stride, despite much of the upheaval relating to the gas market itself. Day-ahead spot leapt to a 4 year high of 80 p/th at one point amid concern over supply, as the UK entered its first winter with no principal (long duration) gas storage facility following the closure of Rough combined with a major explosion at the sensitive Russian import thoroughfare at Baumgarten in Austria. Yet, this barely affected the forward curve in the end. The Annual Contract rose just 2% over the two periods and gas prices actually fell 4% over the year. This relaxed market might symbolize the abundance of global gas supplies relative to oil, and also national aversion to building new gas power stations, efficiency and de-carbonisation globally.

However, gas prices, through oil-indexed contracts and (to an extent still) fuel substitution, will at some point respond to rising energy commodity prices if that trend continues, even if the indexation-lag is pronged (which it often can be). It remains to be seen whether gas prices will remain so calm, even though the forward supply picture remains robust.

Electricity

Forward power prices rose 5% between November and January to finish the year unchanged at roughly £48/MWh. The spark spread has been rising, although whether this will trigger some of the stalled UK gas generation projects remains unclear, with government policy the most likely determinate there. As regards the wholesale market, the outlook for significant price rises in base-load electricity looks muted still. However, for commercial & industrial markets, the outlook is significantly more bullish, with a cocktail of transmission, distribution tariff, existing surcharge and new energy tax rises in the pipeline. These could increase the annual bills for commercial customers by 30% inside three years, notwithstanding changes to wholesale prices.

Despite rising commodity prices elsewhere, forward curve and prompt market prices were also subdued by sentiment on wind generation. A ‘£57.50/kWh’ headline figure made the news in October (although it doesn’t imply many new wind projects will be commercial at such a price) and high winds across Europe in late December also suppressed the day-ahead market. That said, the take-up of renewables combined with certainly lower costs have surpassed expectations, serving to soften forward prices. A cursory look at the ‘speedometers’ on www.gridwatch.templar.co.uk in recent weeks demonstrates just how significant wind output was, amid several Triad warnings in December itself, frequently testing the 9 GW level. This, together with robust nuclear output, compensated for the sudden and unexpected closure of Drax, the UK’s largest power station, despite the outage continuing into the New Year.

This article remains the copyright property of Prospect Law and Prospect Advisory and neither the article nor any part of it may be published or copied without the prior written permission of the directors of Prospect Law and Prospect Advisory.

Prices quoted are indicative and may be based on approximate or readjusted prices, indices or mean levels discussed in the market. No warranty is given to the accuracy of any view, statement or price information made here which readers must verify.

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. 

For more information please contact us on 020 7947 5354 or by email on: info@prospectlaw.co.uk.

For a PDF of this blog click here