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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

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WHOLESALE ENERGY PRICES: SEPTEMBER – OCTOBER 2017:

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

Oil

Crude prices rallied as OPEC and non-OPEC countries continued to show strong quota compliance, with just two cartel producers, Libya and Nigeria, bucking the trend. However, 0in oil trading circles, OPEC’s 1.2 million barrel per day curtailment in export volumes is still remaining on track. Refining inventories have been reported healthy amid a warm start to winter which has suppressed demand for heating oil and related petroleum products. Over the two month period, the Dated Brent contract price closed up by 20%. This spot price has almost doubled in the last two years although it is still just below half the peak it reached barely two years before that.

Traders will be looking for evidence that the ongoing ‘shuttle diplomacy’ in the run up to the cartel’s key 30th November meeting in Vienna is paying off. Given high compliance rates, notably amongst non OPEC countries, there is no reason to expect oil prices to soften with the wind now in the market’s sales.

Natural Gas

The forward calendar year NBP contact finished the period 6% up, with good supply availability and subdued demand both outweighing the effect of steadily strengthening oil prices over the year.

The UK gas market is now into its first winter without any high space (long-duration) storage cover to fall back on. This follows the closure of the Rough gas facility in the Southern Gas Basin. A sustained cold snap could put the market to the test if the UK then has to import (effectively accessing surplus storage overseas) through inter-connectors with Scandinavia and the Continent. Although such pipeline capacity may usually (though not always) be guaranteed on the day, the gas itself is not. Even if so, it will possibly be supplied at higher distress clearing prices than before.

Centrica’s application to withdraw 0.9 billion cubic meters from the 3.2 bcm Rough facility – for site integrity and pressure reduction reasons – has been approved by the UK Oil and Gas Authority and this could keep the market well supplied in the interim. However, the volume is still quite modest and the withdrawals will be phased over time. The impact on the market will be limited, if not discounted already.

With crude prices back above $50/bl for some six months now, the oil markets could soon be nudging gas prices up through long-term contract indexation, especially with increasing reliance on inter-connector supplies given contractual indexation to petroleum product prices is generally more dominant on the Continent than it is in the UK.

Electricity

The annual base-load power price headed back up towards £45/MWh, rising 4% over the period. Although, electricity trading is increasingly becoming ‘a tale of two markets’. Whilst wholesale prices are increasing and may perhaps continue to increase gradually, industrial and commercial tariffs are continuing to climb quite steeply, amid higher transmission, distribution and balancing charges, as well as higher taxes and subsidy-related surcharges applied to industrial and commercial users.

Transit costs and taxes aside, a third factor driving industrial and commercial prices is the increase in renewables generation.

Transmission and distribution networks are known to be struggling to offset the intermittent export supply, current-harmonic and voltage-stability problems which renewable exports onto the system induce. The significant infrastructure investment needed to manage this will be passed on to the end user and increases in producer price inflation will also be an influencing factor. The consensus of recent market research suggests that in less than three year’s time, commodity electricity will account for less than 30% of a typical I&C user’s bill. Five taxes and subsidy surcharges and three grid-system fees will make up the remainder, bar a trace profit for the supplier. Therefore, the rising cost of mains electricity alone could well incentivise more end users to self generate where this is feasible. Fundamental changes to the power market and its subsidy framework to facilitate this trend have been tabled and concrete proposals may be available to report on in 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

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WHOLESALE ENERGY PRICES: JULY – AUGUST 2017:

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

Crude Oil

Forward and spot markets across energy commodities increased over the summer. This was led by crude, which rose over 7% with the futures market buoyed by reports of progress in quota compliance amongst OPEC and OPEC-Alliance producing countries. The geo-political concerns highlighted in July’s issue are also taking hold. Although Latin American tensions have eased, those in the Korean Peninsula remain foremost in peoples’ minds. Indeed, the oil market may be driven higher if more investors view hard commodities as a safe haven.

The refined products markets rose ahead of crude prices amid reports of increased military stocking (chiefly jet-kerosene). Meanwhile, US storms and emergency draws on the Strategic Petroleum Reserve, and also served to drive crude and petroleum products prices up.

Long term hopes for shale took a knock in confidence with an announcement from BHP Billiton that it was selling investments in the US to stem losses on its fracking venture. This news was compounded by comments by the CEO of Total, perhaps the one energy major with the most significant shale involvement, asserting that oil prices will need to stabilise well over $80/bl before any significant new investments can be justified.

Natural Gas

Gas finished the period up more than 3p per therm.

The spectre of North American refiners converging on the Rotterdam spot market drove up European prices for all petroleum products, notably middle distillates. This had a knock-on effect on gas, which is often contractually-indexed to heating oil. It is also a naturally interchangeable refinery product which is frequently blended with kerosene at refineries, hence the strong price correlation notwithstanding the supply basis. This factor and the rise in energy prices across the board perhaps best explains the recent run in gas prices, a market which is otherwise very well supplied, with talk of some LNG cargoes hitherto destined for South Asia now being diverted to European terminals.

Petroleum markets aside, the effects of the weakness of Sterling vs. the Euro, with the determining €/MWh price converting into p/therm, needs to be considered too. The North European gas market is essentially a single, inter-connected supply pool, with the UK price at the National Balancing Point (NBP) essentially ‘set’ by trans-European deliveries cleared in and out of the Title Transfer Facility (TTF) in Holland. A sustained or further weakening in Sterling could put upwards pressure on prices in the UK therefore, especially if regional European spot markets start to tighten once winter takes a hold or we see outages at key power stations requiring an uptake in gas or coal.

Electricity

Wholesale power prices saw the strongest gains of all, with the annual 2017 base-load contract and the spark spread rising 6% and 11% respectively.

Nuclear power stations in France and Benelux, which represent the backbone of the Continent’s supply, had come under increasing safety/decommissioning authority scrutiny, with considerable uncertainty and lack of information on the long-term future of key generators unnerving the forward market.

Industrial electricity prices in the United Kingdom, meanwhile, increased further, partly in unison with steep rises in domestic tariffs and rising input wholesale costs. The impending Energy Intensive Industry (EII) exemption surcharge will soon be affecting end-users on both new and existing long-term contracts from next April. There is some consternation amongst buyers, not just in relation to the justice of the tax itself (which exists chiefly to pay for a tax exemption for larger energy-intensive buyers) but to the uncertainty it is causing as well. Whilst the surcharge will apply from April 2018, buyers still remain in the dark as to what the actual tax rate will be – a case of Whitehall ‘delaying’ bad news, perhaps. Some suppliers have been offering premium-rated ‘insured tariffs’ in response to these end-user concerns.

But perhaps the real ‘elephant in the room’ is inflation. Not so much headline RPI or CPI, but leading-indictor of Producer/Factory Gate prices, with some industry trade associations telling us that such indices are already heading into double figures. Were this to be the case, there are contractual clauses and statutory measures in place to trigger automatic rises across wholesale, industrial and commercial prices. The same inflation-related factors affect the gas market, and in both cases, EUA carbon prices (up by more than 15% over the two month period according to Gazprom Research) could also chase industrial energy costs higher, unless such inflation can be kept in check.

Prospect Law and Prospect Advisory provide legal and business consultancy services for clients involved in the infrastructure, energy and financial sectors.

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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FACTORS TO CONSIDER BEFORE INVESTING IN BATTERY STORAGE: PART II

This new series of blogs highlights the factors which a prospective end-user should weigh up before deciding whether and how to invest in electric storage.

In terms of optimisation, such energy management can be done in-house or outsourced. Although there is no hard and fast rule, outsourcing can bring efficiency and expertise that can far out-weight its cost in commissioning. Fortunately, there are various ways of going about this task and the use of third party agents or an Agency Trader is fairy well established and several firms can offer Agency Trading services.

Although much of the financial model can be prepared by the user’s agent, supplier or prospective manufacturer, the question of intangibles comes up again. Only the user can really determine what the value of continuity and ‘security of supply’ to the business will be: the resilience value overall. It is important, therefore, for the user to be involved in the modelling process.

The cost of modelling varies, as does the quality of much of the work; not always in tandem. In some cases, the cost of modelling should be deducted from the cost of any purchase, if charged. Reputable manufacturers will also inform the prospective buyer of cheaper leasing options which they may have on offer, as well as other alternatives which the user may wish to explore if the financials begin to look marginal.

To clarify, the visible savings of a financial model should include:

  1. Reductions in annual electricity bills: potentially over 50% through Power Purchase Agreement (PPA) tariff reductions or under a bespoke Storage PPA agreed with the supplier.
  1. Future income from Frequency Response services to local distribution networks under private-wire agreements or, in the majority of cases, services to National Grid under reverse auctions.
  1. Optimisation using the battery: This task could be outsourced to an Agency Trader, e.g. a Big Six, independent generator or other energy merchant, who will optimise the battery through their own supply pool and access to the Elexon, OTC, Nord Pool, APX and other markets. This task is less complex than it may sound. Like the battery itself, once in place the process requires little resource from the user, and there are various energy merchants who already offer Agency Trading services, some paid on performance only.
  1. Peak Shifting: the ability of the user or embedded generator to ‘time’ their exports of the electricity they sell into the system and so attract higher ‘peak’ prices in trading markets. Again, an Agency Trader could facilitate if the end user does not wish to becoming involved in trading directly, as many may not.
  1. Enhanced Plant Efficiency: alleviating excess loads, avoiding ‘cold starts’ and mitigating other impacts to prolong the life and reliability of turbines, minimise wear on machinery and preclude erroneous reset of control systems which some ‘black box’ DSR systems might place at risk.

It is worth adding here that larger businesses have the option of a Guest Battery. The business will not buy the battery nor pay for anything related to it, but will simply make land available and allow the Provider to install and operate the Guest Battery. The user receives pretty much the same electricity bill savings outlined in paragraph 1 above and the Guest Battery also adds a valuable degree of ‘free resilience’ as well. To compensate the Provider for such benefits, which entail practically zero cost and zero risk, the user must agree to share any resultant cost savings with the Provider.

In evaluating the resilience benefit for the company, it is important to consider:

  • The cost to the business of any ‘worst case scenario’ occurring within five, ten or fifteen years without any emergency cover or 100% dependable back-up. These will include direct contractual losses and/or consequential damages relating to any power outage, whether it was caused internally or by an outside issue with the local distribution, high-voltage transmission grid or generator: be it human error, one of the cyber attacks targeting grids of late, a force majeure or any other unforeseen event, which may or may not lie within the user’s control but remain his financial responsibility.
  • The alternative cost of buying ‘critical loss’ cover or very high premium catastrophe insurance (if it is available) that may be sure to protect the business from damages resulting from short-term or prolonged outages.

Whether or not a battery is finally purchased or leased, the process of exploring this investment can be useful as it will focus attention on optimisation options for the plant itself. The exercise can serve as a ‘de facto’ energy heath check and is offered free by some providers. This exercise must also establish what battery chemistry is best suited for the user, the size and performance specification of any battery, as well as the exact type of long-term warranty on offer, with questions pertaining to its operational life, the number of complete and partial cycles; its flexibility, its depth of discharge, specified breeches and allowed tolerances that may void a guarantee.

The forward service provision is just as important as the battery itself. It is another key question which the agent, supplier or manufacturer will need to be asked.

This article has analysed the visible savings a financial model should include, and has also introduced factors to take into account when evaluating the resilience benefit for a company. Click here to read Part I, which discussed the importance of valuing benefits, visible and intangible, and including them in a financial mode.

By Dominic Whittome 

Prospect Law and Prospect Advisory provide legal and business consultancy services for clients involved in the infrastructure, energy and financial sectors.

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.

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 various 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.

Click here for a PDF of this blog

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WHOLESALE ENERGY PRICES: MAY – JUNE 2017:

In this series of articles, Dominic Whittome covers recent changes to wholesale energy prices.

Crude Oil

Brent crude fell $51.75 to $48.85/bbl amid concern that OPEC and OPEC Alliance states have still been struggling to remove the slack from the oil market, also rising exports from Libya (adding over 1 mbd) and from Nigeria (over 1.7 mbd) to world supplies. Neither oil producer is covered by the production accord.

Oil prices fell by just over 5% which seems a comparatively modest fall put in perspective and against recent newswires and headlines on the subject.  Looking at the price upside, markets will be concerned at growing global oil consumption, notably in the automotive sector, the prospect of faltering supplies and the possibility of deeper OPEC Alliance cuts, which may well happen if it is now clear that the existing cuts do not go far enough.

On the downside, the market will be looking at future output increases in Libya, Iraq and North America. Shale exports are clearly having an impact, although longer-term questions about the sustainability and commercial viability of sub $80/bbl production projects outside Africa and the Middle East  are likely to remain. Ongoing political troubles in South America and the South China Sea may also rattle petroleum markets in the weeks ahead. Furthermore, with derivatives now accounting for most of the open positions in the forward markets, physical prices may  be very sensitive indeed to general shifts in perception, even if the market looks calm at the moment with the 15 Day Brent contract seemingly stuck between the same £45/bbl  ‘floor price’ and £55/bbl resistance level mentioned in the last edition of this update.

Natural Gas

Gas prices barely moved over the period, up just 2%. The main news last month was the announcement that Centrica will permanently shut its Rough facility. This is a converted North Sea gas field which, as most articles reported, accounts for 75% of the UK’s storage  capacity. While that percentage is perfectly accurate, in terms of the ‘high-space/low-deliverability’ storage (i.e. the type the market needs to balance on a seasonal basis and to provide cover for prolonged emergencies) the true percentage cover  which is provided by Rough is even higher, possibly over 90%.

The closure of such a strategic asset should be a concern therefore.  The last 15 years have seen new investment in onshore salt-caverns, although these are generally ‘low-space/high-deliverability’ assets. Although they are more flexible, the emergency cover they can provide is limited. They are also likely to be more expensive, certainly once competition hitherto provided by Rough is withdrawn.  The closure of Rough may therefore expose the UK gas balancing market to  technical and market developments relating to these smaller storage facilities, the LNG market and inter-connectors.

Consequently the risk-premiums in I&C contracts may rise (due to higher balancing risks), as will valuations of swing flexibility in North Sea gas sales agreements. From a North European perspective, the gas market does look well enough supplied for now. However, the Russian-Ukraine corridor, South East Asian LNG supply, demand and geo-political developments all need watching in the weeks ahead, as well as the oil market itself.

Electricity:

The forward baseload contract finished the period unchanged at £43.00/MWh.  New delays were  announced for the proposed 3,200 MW Hinkley Point C  nuclear power station and the plant now looks unlikely to generate at full capacity until 2027, by which time all of the UK’s remaining reactors, bar Sellafield, may have closed.

Progress on the next new-build site, the 3,600 MW Moorside plant, looks to be in jeopardy altogether, with primary shareholder Toshiba facing  possible insolvency and minor partner Engie (formerly Gaz de France) pulling out of the project altogether.  Power prices are being held down by low oil and gas prices for the time being but the long term outlook is less clear. To ensure the system has adequate volume, National Grid and central government have  embarked on quite an extensive portfolio of new inter-connector projects to import from grids on Continental, Scandinavian countries and potentially Iceland, which has a 1,500 MW wire hoping to get the go-ahead soon.

There are already eleven major inter-connectors, rated between 1,000 MW and 2,000 MW, planned under construction or already live. But whilst the system may have the capacity spare, this is no guarantee that sensibly-priced electricity itself will be available to fill any short-fall. The UK’s price-dependence on European and Nordic power exchanges looks set to increase. The landscape will be different with the current inflation-adjusted Strike Price for the first new-build reactor at Hinkley Point C already weighing in at £110/MWh, much higher than the existing baseload market prices.

Barring a renaissance in gas-fired or other indigenous generation, forward power prices look poised to shift higher. Significant increases in trend are perhaps most likely in the balancing market prices rather than baseload, with the latter fast becoming ‘the residual’ commodity by comparison. As we go to wire, there are reports that half of France’s nuclear power plants are in shut down. It is not clear why or when plants will re-start. Twenty units offline cannot be explained by maintenance although there is a host of possible reasons to explain what has happened and no report yet of any sharp movement in European power prices.

By Dominic Whittome

Prospect Law and Prospect Advisory provide legal and business consultancy services for clients involved in the infrastructure, energy and financial sectors.

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 various 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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FACTORS TO CONSIDER BEFORE INVESTING IN BATTERY STORAGE: PART I

This new series of blogs highlights the factors which a prospective end-user should weigh up before deciding whether and how to invest in electric storage.

The decision whether or not to invest and, if so, exactly which type of package to go for, will depend on a host of factors. These include the nature and configuration of any embedded generation, the user’s demand profile and the value of ‘security of supply’ to his business.

We should split the ‘all in’ value of electric storage in two parts.

  • Visible benefits: these include the added value to the business through reduced annual power bills; enhanced micro-generation efficiency; improved power quality; energy efficiency and additional plant income, such as Frequency Response revenues from grids or other customers. Each Visible benefit should be quantified and included in the financial model.
  • Intangible benefits: these cover security of supply or ‘resilience’, i.e. the added value to the corporation in the form of ‘business continuity’, ‘catastrophe avoidance’ amongst other liabilities a plant manager may hold responsibility for.

In each case, especially the first, it is important to avoid double counting when valuing benefits and including them in a financial model. For example, if a user employs a battery to sell a specific service to a third party, like a high-flexibility Frequency Response service to National Grid, this could conflict with other uses the battery may be needed for in the event. Fortunately, there are now twenty-seven different Frequency Response categories which National Grid is inviting through its 2017 reverse-auction process, i.e. these include cheaper, less flexible types of service, precisely to address such conflicts and to encourage storage users to free up and sell them any surplus capacity they may have to spare.

Above all, the commercial payoff of a battery will ultimately depend on how well it is specified and installed and how well it is optimised subsequently, both on-site and out in the marketplace.

Some batteries installed recently operate profitably as ‘standalone projects’. Here the visible benefits alone justify the expenditure; resilience is just a bonus. The main benefits involve Frequency Response income and/or annual electricity bills savings of circa 50% to 60% by virtue of an effectively flattened demand-profile, avoiding the Climate Change Levy, TRAID and Red Zone capacity payments to the system.

Other batteries might only be considered worthwhile once visible and intangible benefits are considered together, chiefly in cases where ‘business continuity’ is seen as critical and so resilience becomes the principal value that a battery will provide.

The visible benefits may be of secondary importance. This value still needs to be evaluated separately and be viewed as a way of subsidising the battery.

Financial modelling relies on detailed user profile, power market data and complex forecasting techniques. The storage arena is relatively new and highly sophisticated, even by power generation industry standards. However, some robust financial models have been developed, prepared by a prospective end user’s own agent, battery supplier or manufacturer. Although not perfect, certain models should give a prospective buyer a good ‘feel’ of the investment return they can expect, also flag up whether or not storage itself is a sensible option, and if not what alternative optimisation or Resilience options may be worth looking at.

This article has discussed the importance of valuing benefits, visible and intangible, and including them in a financial model. Part II of this series will analyse, in greater detail, the visible savings a financial model should include, and will also introduce factors to take into account when evaluating the resilience benefit for a company.

By Dominic Whittome 

Prospect Law and Prospect Advisory provide legal and business consultancy services for clients involved in the infrastructure, energy and financial sectors.

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.

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 various 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