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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.

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OFGEM’S CONSULTATION ON THE PROPOSED DEFINITION OF ENERGY STORAGE

Introduction

Ofgem are consulting on the legal definition of “energy storage” and the introduction of a new condition in the electricity distribution licence designed to ensure that distribution system operators, also known as distribution network operators or DNOs, cannot operate energy storage assets (https://www.ofgem.gov.uk/publications-and-updates/clarifying-regulatory-framework-electricity-storage-licensing). The Ofgem consultations both close on 27 November 2017.

The UK has eight distribution network operators (DNOs). They operate the regional networks that deliver electricity to consumers after it has been transmitted on the UK’s national high voltage transmission network. As natural monopoly service providers, DNOs are arguably well placed to develop energy storage facilities.  Indeed, several DNOs are already actively developing energy storage projects, including Western Power Distribution and UK Power Networks.                                          (http://innovation.ukpowernetworks.co.uk/innovation/en/Projects/tier-2-projects/Smarter-Network-Storage-(SNS)/Smarter%20Network%20Storage%20FAQs.pdf).

Proposed change to EU law

Ofgem’s position appears to be influenced by proposed changes to EU law. The European Commission’s recast of the Electricity Directive recognises the need for consumers to actively participate in electricity markets, including storage, it provides:

“The electricity market of the next decade will be characterised by more variable and decentralised electricity production, an increased interdependence between Member States and new technological opportunities for consumers to reduce their bills and actively participate in electricity markets through demand response, self-consumption or storage.

The present electricity market design initiative thus aims to adapt the current market rules to new market realities, by allowing electricity to move freely to where it is most needed when it is most needed via undistorted price signals, whilst empowering consumers, reaping maximum benefits for society from cross-border competition and providing the right signals and incentives to drive the necessary investments to decarbonise our energy system. It will also give priority to energy efficiency solutions, and contribute to the goal of becoming a world leader in energy production from renewable energy sources, thus contributing to the Union’s target to create jobs, growth and attract investments”. 

In terms of specific detail, Article 36 of the recast for the Electricity Directive proposes a general prohibition on DNOs owning, operating or managing energy storage facilities:

Article 36
Ownership of storage facilities
  1. Distribution system operators shall not be allowed to own, develop, manage or operate energy storage facilities.
  2. By way of derogation from paragraph 1, Member States may allow distribution system operators to own, develop, manage or operate storage facilities only if the following conditions are fulfilled:
(a) other parties, following an open and transparent tendering procedure, have not expressed their interest to own, develop, manage or operate storage facilities;
(b) such facilities are necessary for the distribution system operators to fulfil its obligations under this regulation for the efficient, reliable and secure operation of the distribution system; and
(c) the regulatory authority has assessed the necessity of such derogation taking into account the conditions under points (a) and (b) of this paragraph and has granted its approval.
  1. Articles 35 and Article 56 shall apply to distribution system operators engaged in ownership, development, operation or management of energy storage facilities.
  2. Regulatory authorities shall perform at regular intervals or at least every five years a public consultation in order to re-assess the potential interest of market parties to invest, develop, operate or manage energy storage facilities. In case the public consultation indicates that third parties are able to own, develop, operate or manage such facilities, Member States shall ensure that distribution system operators’ activities in this regard are phased-out. (http://eur-lex.europa.eu/legal-content/EN/TXT/HTML/?uri=CELEX:52016PC0864&from=EN)

The prohibition on DNOs owning energy storage in paragraph 1 of the proposed Article 36 is subject to a derogation in paragraph 2 that provides that DNOs can own, develop, manage and operate energy storage facilities if they are needed to ensure that a distribution network is efficient, reliable and operates securely. Paragraph 2(c) provides that it is for the regulatory authority of a Member State to assess the necessity of a derogation.

DNOs as neutral market facilitators and the new reality of the UK’s energy market

The rationale for the proposed prohibition in Article 36 is that DNOs should act as neutral market facilitators. A white paper published by the Agency for the Cooperation of Energy Regulators (ACER) on 15 May 2017 explains the decision to adopt this policy position:

“European Energy Regulators advocate that DSOs must act as neutral market facilitators performing regulated core activities and not activities that can efficiently and practicably be left to a competitive market. This approach is important because:

  • Competitive markets are generally better than regulated markets in delivering outcomes that provide best value for money for consumers;
  • When DSOs get involved in competitive activities – such as storage – there is a risk that they would favour their service over potentially cheaper services (e.g. storage over demand-side response), thereby raising costs and deterring investment and innovation;
  • DSOs could unfairly favour different types of consumers if they are direct market participants for these services; and
  • Confidence in the neutrality of DSOs is a key element of the market.”

In contrast, 10:10, a UK registered charity that focuses on tackling climate change at community level, has argued against the UK adopting a general prohibition on DNOs owning energy storage facilities:

“If [DNOs] are not permitted to own and operate their own storage assets, this is likely to increase costs for end users as a consequence of increased transaction costs between network and storage operators. Network companies should be allowed to judge where and when to procure storage from a third party, and when and where to own it themselves.”

A recent survey by Energyst, the energy magazine, has also noted National Grid’s need for more firms to help it balance the power system (https://theenergyst.com/20-firms-outline-what-is-stopping-them-providing-demand-side-response/). According to Energyst:

“With some 35GW of renewables on the system, more than a third of it solar PV, summer may become as much of a challenge as winter. That equates to a year-round revenue opportunity from National Grid alone. Yet relatively few firms provide balancing services via their onsite generation or ability to shift loads. Why?

According to The Energyst’s reader surveys, this is for a few key reasons, mainly fear of technical failure and/or incompatible processes and insufficient financial reward. But lack of understanding and the fact that the most UK firms have not been approached by either aggregators or energy suppliers regarding DSR are also factors…

…But these early survey findings suggest there remains a need for better communication and cost effective technology solutions if DSR is genuinely going to trickle down from large power users to the broader market.”

The problem with DNOs acting merely as neutral market facilitators is that a lot of energy storage is likely to be needed in the UK (http://fes.nationalgrid.com/media/1253/final-fes-2017-updated-interactive-pdf-44-amended.pdf – see pages 104-105).

Energyst’s research suggests that there may not be sufficient interest from third parties to provide energy storage. 10:10 have put forward the argument that DNOs would be well placed to provide storage at the lowest cost. If this is correct, a complete prohibition on DNOs owning energy storage facilities would not reflect the “new reality” of the UK’s energy market and would also overlook the derogation in paragraph 2 of the proposed Article 36.

Conclusion: Are DNO energy storage targets a potential solution?

Notwithstanding Brexit, Ofgem seem to want to follow the EU’s proposed position on this issue.

A potential solution would be for the UK to set individual targets challenging each DNO to procure a certain level of energy storage facilities. Should a DNO be unable to meet its target through an open and transparent tendering process, then it should need to develop, own, manage and operate the balance to ensure that it has an efficient, reliable and secure distribution system.

It should be possible for the UK to draft a regulatory solution that is compatible with the derogation set out in paragraph 2 of Article 36 of the proposed Electricity Directive.  However, whether or not this solution would satisfy Professor Helm’s desire to remove all regulatory interventions from the UK energy market is another question.

Tim Malloch, 03 November 2017

About the Author

Tim Malloch trained at Macfarlanes and subsequently moved to Freshfields Bruckhaus Deringer, where he advised on corporate transactions and finance projects. After 7 years at Freshfields and a sabbatical spent abroad, Tim joined ClientEarth, an award-winning legal NGO, and devised a litigation strategy that helped persuade the UK Government to abandon its plans to build a new generation of coal power stations.  Tim returned to private practice in 2010 and has advised on a wide range of high-value commercial disputes.

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.

For more information please contact Tim Malloch on 020 7947 5354 or by email on: tmm@prospectlaw.co.uk.

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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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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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PREPARING FOR ACCIDENTS, SPILLS AND DISASTER IN THE UK: PART I

Incidents which cause environmental harm or injury and illness to workers or neighbours can have significant consequences for the companies responsible.  Preventing those incidents must, therefore, be a priority, but if they happen they must be managed so as to minimise physical and environmental damage, liabilities and the risk of an adverse regulatory and media response. This new series of articles summarises key issues for companies operating in the UK, with the first part focusing on prevention and the immediate incident response.

Prevention:

To prevent incidents, management needs to understand the legal obligations affecting their operations including requirements for environmental permits and licences, prohibitions and restrictions on pollution, duties to avoid unduly disturbing neighbours, and duties to protect employees and others.  At the operational level that involves familiarity with permit and licence conditions, as well as procedures which implement both those conditions and general environmental and health and safety (EHS) laws.  That task can seem daunting, and in response, many companies produce bulky EHS manuals with detailed instructions on how to deal with every eventuality.  The problem is that few people have the time to read them.

Brief, clear written instructions on how to avoid EHS incidents are more likely to be effective.  However, clear written instructions alone are rarely sufficient: busy workers may overlook them.  “Tool box” talks are an invaluable way of ensuring that employees know how to: protect the environment, promote health and safety and minimise the company’s risk of liability.  Examples of points to cover in a toolbox talk include which liquid substances should or should not be poured into particular drains and sewers; and what to do and who to report to if equipment or plant is found to be defective, corroded, dangerous or likely to result in unlawful emissions.  A toolbox talk also could cover simple operational procedures to ensure compliance with permit conditions and other legal requirements, and good housekeeping “rules”.  Bold and simple notices may also serve as useful reminders.

Incident response:

If an incident has adverse EHS consequences, the first priority is to minimise its consequences. Also, a decision must be made whether to notify the relevant regulatory authority, and how to deal with regulatory officers if they carry out an investigation. Those issues are likely to affect the regulatory outcome.  Many EHS incidents are strict liability criminal offences (no negligence or intent has to be proved), but the extent of culpability as well as the company’s behaviour after the incident has a profound effect on the authority’s approach (particularly the decision on whether to prosecute) and on the amount of any fine imposed by the courts.  Recent guidance from the courts in the UK, as well as official sentencing guidelines, have markedly increased the normal range of fines with the intention that the punishment should be real.

There is no uniform answer as to whether and when to contact the regulatory authority.  Each case depends on the circumstances including legal and permit requirements.  Generally, except in the most minor incidents, it is safer to report the matter to the local officer of the regulator by e-mail (to ensure that there is a record) and by telephone as soon as possible after the incident.  The initial report should be brief and factual, explaining what has happened and the steps being taken to deal with it.  The incident manager should send it.  Above all, the notification should not accept blame on the part of the company.

Part II will cover dealing with the regulators and investigating officers’ powers to take statements from witnesses.

By Andrew Waite

This article was first published in Natural Resources & Environment  (the American Bar Association’s Environment Magazine) Spring Issue 2017.

Andrew Waite is a solicitor and specialist in environmental law, advising on regulatory and liability issues for a broad range of industries.  He defends prosecutions for breaches of environmental legislation, deals with regulatory appeals and civil litigation and advises on environmental issues relating to projects and transactions.  He deals with all the main areas of environmental law including waste, energy, nuclear, contaminated land, pollution controls, environmental permitting, water rights, flooding, climate change and nature conservation.

Prospect Law and Prospect Advisory provide a unique combination of legal and technical advisory services for clients involved in energy, infrastructure and natural resource projects in the UK and internationally.

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WHOLESALE ENERGY PRICES: JANUARY – FEBRUARY 2017: PART I: CRUDE OIL & NATURAL GAS

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

Crude Oil

Oil prices finished 2% down as the market remained pensive about the upcoming OPEC summit in April.

Although ‘OPEC Alliance’ countries (producers co-operating with latest output cuts) will not be attending the Vienna talks in a formal capacity, behind-the-scenes dialogue has been ongoing all the while.

With Iranian and Russian ministries having met up in January to discuss Russia extending its production cuts into next year and Saudi Arabia sending their foreign minister to Iraq (which was included in its latest production agreement) with a view to including Iraq in possible future production ceilings yet to be agreed.

Traders have been pointing out that there is no evidence to show that last November’s accord between OPEC and OPEC Alliance countries made any impact. Although it is true enough that crude prices have flat-lined since November (having jumped in the weeks running up to the accord), conversely there is also no sign the accord has not worked. The agreed cuts were modest, the first in over nine years and also the first of their kind in that they included several non-OPEC producers.

OPEC ministers are possibly playing a long game, with modest but universally-orchestrated limits in output, to be increased methodically rather than in any way likely to destabilise the market, and we would need to wait and see if and what OPEC ministers decide on in April before one can second-guess the success or otherwise of last November’s accord. The pace of oil price recovery has, however, been muted. This may or may not be connected to the delays to the public listing of Saudi Aramco, ostensibly due to ‘complexities in the structure’ of the company flotation plan.

The mooted delay (up to 18 months) may reinforce scepticism about the expected speed of any oil price recovery, if this reflects the kingdom’s pessimism of the accord holding together. The value of the share offering is estimated at over £2 trillion and clearly very sensitive to prevailing oil prices. If market estimates are correct, the new company is valued at 20 times the capitalisation of the next largest oil major, ExxonMobil. It is conceivable that there have been worries that the oil market might not recover in time and these may have played a factor in the delay, although that itself is pure speculation. The Vienna meeting April could though be a turning point, in either direction.

With this week being CERA Week in Houston, perhaps we can expect the annual splash of shale stories over the next few days.  While shale drilling should place a price ceiling on any sustained oil price recovery, as pointed out in past issues of Energy Highlights, shale plays are generally short-term and expensive. Oil prices could comfortably ratchet up to $75/bbl or beyond before shale and higher-cost conventional oil output starts to kicks-in. Either way, the oil market will never loose its capacity to take people by surprise.

Natural Gas

The forward-year gas contract finished the first two months of the year off 10%, closing below 45p per therm. This reflects the view held by most traders of a fundamentally well-supplied market with a spate of further LNG export projects set to come online this year and next, many landing at European terminals.

Notable supplies include projects in Australia and South East Asia, although shale gas from the Americas will have a role will to play too. The UK market recently saw shale gas imports from the Peruvian jungle due for landing at Milford Haven shortly before going to press, and this healthy looking forward supply-picture has been helped along by Japan.

The country has gradually been releasing more and more gas on to the world spot market: the LNG contracts it had bought up in the immediate aftermath of Fukushima. This may have contributed to (or certainly given the impression of) an ‘LNG glut’.

The demand-side also paints a weak picture, with limited demand-call from generators and industry. However, there are some bullish signs on the horizon too. Geo-politics have recently turned adverse, with under-the-radar conflict areas in Russian-Ukraine and even the South China Sea among the potential supply-area worries.

However, any sustained uplift in gas prices is perhaps most likely to occur as a result of an indexation and long-term contracts issue. Indexation to crude prices still has the propensity to push prices up, with much of the piped and LNG sold across Europe still covered by these clauses. Within these contracts, even where oil and petroleum product indices may have seen their price-impact reduced or possibly removed altogether over the last 20 years, these price escalators indices have in most cases simply been substituted for producer price indices, which have recently been rising faster than oil prices themselves.

In fact, over the last five months alone, UK producer prices have been rising at annualised rates well over 10% according to estimates provided by industry trade associations. These will ultimately soon be reflected in official government statistics and will later directly influence gas contract prices, where the indexation effects can be lagged for six to nine months or, in unusual cases, even longer.

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 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 various private entities on a range of energy origination, strategy and trading issues.

For more information please contact us on 020 3427 5955 or by email on: info@prospectadvisory.co.uk.

For a PDF of this blog click here

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WHOLESALE ENERGY PRICES: SEPTEMBER – NOVEMBER 2016: PART I: BRENT CRUDE & NATURAL GAS

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

Brent Crude

September started strongly for the crude market amid hopes of an early OPEC production cut, linked to a production sharing accord with non-OPEC producers. However, dated Brent subsequently fell back below $50/bl as a deal proved elusive and traders grew weary of another false dawn.

Production limiting accords between the cartel and non-OPEC countries (including Russia, even Norway on one occasion) are not unprecedented and have been sustainable for quite long periods in the distant past, so this topic shall remain on the market’s radar. Oil prices could be supported further if European refiners restock and delayed winter weather increases demand for middle distillates on the Rotterdam spot market, which has already had a strong few months.

Crude ended the month period 7% higher although prices have drifted downwards again quite recently.  The market is unlikely to  rise far above its current support level, discussed at around $45/bl, unless we see some concrete signs of progress in Vienna in the coming weeks.

Natural Gas

The low, sub-$35/bbl crude oil prices witnessed earlier in the year have mostly dropped out of pricing formulae in Norwegian, Dutch and Russian long-term contracts.

Gas traders are also believed to be cautious about the delicate supply and demand balance and a late start to winter. The consensus of longer-range meteo offices seems to embody a higher degree of uncertainly versus last year and generally they point to a colder than normal winter.   This, together with the blight in LNG imports into the UK, has supported the gas market. Short term prices meanwhile ticked up as Centrica confirmed delays to bringing its Rough platforms back on stream, the UK’s principal gas storage facility.

Gas withdrawals are  now  planned to resume during December although any further delays may coincide with extreme demand periods and cause prices to spike.  Additionally, the rampant price volatility on the electricity balancing and prompt markets has driven gas prices upwards. Consequently the forward market has bounced with the April 2017 contract ending the period over a fifth higher. The market will be vulnerable to further increases should we see any unscheduled interruptions to North Sea or trans-Continental supplies, although the supply side has been holding up fairly well over the past few weeks.

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 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 various private entities on a range of energy origination, strategy and trading issues.

For more information please contact us on 020 3427 5955 or by email on: info@prospectadvisory.co.uk.

PFor a PDF of this blog click here

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LARGE SCALE BATTERIES FOR ENERGY PROJECTS: FLOW TECHNOLOGY

This series of articles highlights the commercial case for two different types of large scale battery. Large scale batteries widely differ in terms of their flexibility, life-time resilience, day-to-day reliability, initial purchase price (or CAPEX) and the ongoing cost of their maintenance & upgrades (OPEX). It is, obviously, crucial to identify the right battery design and manufacturer.

Flow technology (1974) is older than Lithium (1986), but is not portable and generally less well understood. As recent technology breakthroughs makes Flow an alternative to Lithium and Sodium Sulphur, a quick background explanation may be useful.

Flow Batteries: 

Electricity is stored in electrolyte liquid in two storage tanks. The tanks feed (via pumps) into their own half-cell, each separated by an ion-exchange membrane or ‘exchanger’ (a delicate graphite film manufactured by Du Pont).

The same substance, vanadium is dissolved in sulphuric acid (solving the contamination problem which dogged other designs) is stored in both tanks but at different states of charge.

Vanadium ions are exchanged across the membrane as pumps are activated. Chemically-stored energy is 100% transferred into electrical energy (and 100% back from electrical energy to chemical energy when the battery is recharging).

Pros:

  • High round-trip efficiency, but slightly below ‘high-end’ Lithium and Sulphur designs. Yet significantly more flexible, reliable and versatile out in the field. Flexibility to charge / discharge up or down to any level with no wear or tear issue.
  • Capacity to reverse-flow i.e. charge-discharge-charge inside a 100th of a second’s notice.
  • This Flexibility makes them suitable for both Frequency Response and for Primary Control. Reserve/Storage i.e. one can use the same unit battery to fulfil both tasks and avoid overspend.
  • This cycling/frequency-response flexibility makes Flow suited to successive peak-shifting and arbitrage. This can earn a second revenue for the owner and help to pay down CAPEX. A commission Agency Trader (e.g. big six generator on commission can optimise the battery and extract trading economies of scale for the battery investor).
  • The storage capacity of a Flow battery is simply determined by size of the storage tanks.
  • Flow batteries have a higher CAPEX than Lithium or Sodium-Sulphur. However Flow batteries are more reliable and they require less maintenance. Also OPEX is low – circa 2.5% of CAPEX (less than Lithium or Sodium-Sulphur). For this reason, Flow batteries are generally the cheapest option when the full life-cycle of the system, including maintenance, repairs or part replacement are included in the calculation.

Cons:

  • Flow batteries are a less well known, less common and less understood technology. For this reason alone, they can be harder to win support from internal finance directors and external financers.
  • Flow batteries are less portable than many solid-state batteries due to their low energy density.
  • There are fewer Flow battery manufacturers and still many different variants of flow battery.
  • They use corrosive acid as the electrolyte which requires a robust and expensive membrane (the exchanger) for use in every cell. This cost can mount up and it partially explains the high price of Flow batteries. Continuous RND costs is another significant overhead which the consumer ultimately pays for in terms of CAPEX.
  • A Flow battery has a lower energy density than any Lithium Ion or Sodium Sulphur battery and so the actual space required to house this storage is significantly greater.

Lithium Ion v Flow Battery: Conclusion

A Flow design involves significantly less maintenance than a Lithium Ion or Sodium Sulphur.

The Vanadium variant battery (same electrolyte solution used in each tank (i.e. on both sides of the exchanger) has solved the ‘cross contamination problem’ with Flow technology.

OPEX is more quantifiable at the project outset than in a Lithium-ion battery. OPEX will be lower: ca. 2% of CAPEX vs. a significantly higher OPEX figure for Lithium Ion. e.g. replacement cells, annual maintenance and inspection of fire-prevention systems.

Consequently, the Flow battery is claimed to be the cheapest ‘Lifetime Option’ as well as the most robust and flexible alternative.

Recent trends in global Lithium Carbonate prices may conceivably lead to unaccounted for (all prices quoted are subject to change) increases in CAPEX cost or (perhaps more likely) increases in future OPEX costs.

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 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.

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 3427 5955 or by email on: info@prospectadvisory.co.uk.

F0r a PDF of this blog click here

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WHOLESALE ENERGY PRICES: MAY 2016 – JULY 2016: PART II: ELECTRICITY

In this series of articles, Dominic Whittome covers wholesale energy prices between May and July.

Firming prices for coal, the buoyant gas market and some concern over the timing of infrastructure projects after Brexit helped base-load power prices surge a further 15% over the period. The notional spark spread (undiscounted for carbon prices) increased 21% to £13.50/MWh.

Any future rises in base-load power prices may underplay the final PPA contract price rises for industrial users as the gap between base and peak load prices widens. Elexon’s maximum System Reserve Price is slated to increase to an unprecedented £5,000 MWh (£5/kWh) within two years. The main jump (to £3/kWh) was instigated last year. Although Cash Out prices will seldom reach such levels, forthwith Ofgem will allow such prices to happen. This shows how the balancing market will value peak-plant and storage-flex capacity in future. Further, the decision (made before the Brexit result) by National Grid to stick to half-hourly trading windows after all and not adopt a European-style 15 minute regime will, if anything, maintain the pressure on peak prices, with Elexon left to keep the system balanced over the existing, longer balancing period.

Brexit could conceivably affect the outcome of the proposed 3,200 MW reactor at Hinckley Point, whatever that may be, as this may depend on the new administration in Whitehall, given the political capital invested and still required by this project. Most of the focus has been on the £20bn + construction cost, underwritten by the taxpayer under a Treasury loan guarantee. There has been less focus on the Contract for Difference subsidy – a totally separate form of project support. This potential cost is underwritten by end users, reflected in their electricity bills.

Assuming a Forward Year Baseload price of £45/MWh and the CFD ‘s Strike price (£92.50 MWh at the time of signing +  accumulated price indexation to the present day) of £100/MWh i.e. both in today’s money, then the value of this subsidy can be calculated 3,200 MW x £55/MWh x 24 x 365 x 35 = £ 54 bn. This estimate is a speculative one. It will only fall if power prices increase rise relative to the inflation-indexation of the Strike Price.  This £54 billion figure represents the cost of the subsidy only. The electricity volume itself still has to be purchased by consumers in the normal way.

The estimate calculated should be close to the mark, provided our CFD contract assumptions are correct and Baseload power prices not rise substantial in real terms. It is worth noting that it is Peakload rather than Baseload generation which is generally recognised as the commodity that the system has in short supply. If new-build nuclear projects planned for Wylfa, Sellafield and Bradwell command similar subsidy terms, then combined support cost for all four new nuclear power plants could surpass £200 bn.  One effect of Brexit therefore could be to bring these financial considerations into the spotlight. Possibly rekindle the debate over the future of coal and gas generation, if the imminent Westminster government uses the Leave vote as a moment to revisit energy policy.                                         

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 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 various private entities on a range of energy origination, strategy and trading issues.

For more information please contact us on 020 3427 5955 or by email on: info@prospectadvisory.co.uk

For a PDF of this blog click here

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WHOLESALE ENERGY PRICES: MAY – JULY 2016: PART I: OIL AND NATURAL GAS

In this new series of articles, Dominic Whittome covers wholesale energy prices between May and July.

Oil

Crude prices continued rising in spite of little progress towards an OPEC production ceiling. The market shrugged off the continuing discord between producers and a recent International Energy Agency report highlighting a potential 3  – 3½ million barrel a day glut set to overhang the market next year. The physical 15-Day Brent contract closed the two month period up another 5%. Prices remain comfortably above the new $25 – $35/bbl range talked about in London oil trading circles as recently as March/April.

Concerns over the future cost of mobilising non-OPEC supplies in order to make up any OPEC shortfall may continue to support the market for the meanwhile. Looking further ahead, it may be the case that that only after oil prices reach £75/bbl and look like staying above this level may we see any real dampening effect on the market through new shale exports from North America.

Natural Gas

Despite seasonally weak European demand, significant contractual oil price de-coupling in Russian and, reportedly, Norwegian contracts too, the Annual October ’16 gas contract at the NBP continued to advance amid supply issues in the North Sea and the prospect of costlier imports from Europe in the aftermath of Brexit and a sustained weaker value in Sterling. If such concerns are founded, this would push the winter UK market higher with €/MWh price at the Dutch TTF hub increasingly influencing marginal prices through the UK-Zeebrugge Interconnector.

Looking somewhat further ahead, the abrupt seeming thaw in diplomatic relations between Russia and Turkey might signal the Blue Stream 2 export project back on the cards. This would mobilise further gas supplies to the Continent and help Turkey to establish itself as a major gas hub, a regional thoroughfare for both Russian and future Iranian gas export into Europe.

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 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 various private entities on a range of energy origination, strategy and trading issues.

For more information please contact us on 020 3427 5955 or by email on: info@prospectadvisory.co.uk.

For a PDF of this blog click here