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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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IRAN NUCLEAR DEAL – HAS TRUMP GOT IT RIGHT?

Is President Donald Trump alone in his criticism of the “Iran nuclear deal”? And was his decision to withdraw from it a wise one, based on facts rather than conjecture? This “deal”, officially known as the Joint Comprehensive Plan of Action (JCPOA) was signed in July 2015 by Iran, the five permanent members of the Security Council (China, France, Russia, UK and US), Germany and the European Union. Of course, the US signed it under the Obama administration and President Trump made no secret of his opposition to it during his election campaign; as with “Obamacare”, was his main reason for withdrawing from the deal because it was implemented under the previous administration?

HISTORY

What do people say is wrong with the deal? Ironically, Iran’s civil nuclear development programme started in the 1970’s with assistance from the US under the Atoms for Peace programme. Under this, the US deployed many nuclear research reactors around the world and supplied the associated nuclear fuel.

Since those early days, Iran’s nuclear programme has gone through many changes, but to many, in recent years, it was pursuing what appeared to be its own nuclear weapons development programme. Like any country signed up to the Non-Proliferation Treaty (NPT), which Iran became party to in 1970, it has a right to undertake research into the production of nuclear energy for peaceful purposes. Iran protests that its research was purely related to power generation was not helped when the existence of previously unknown uranium conversion and enrichment facilities, which could be related to nuclear weapons research, were revealed in the early 2000’s. For a chronology of key events in Iran’s nuclear history see here.

Attempts to curb Iran’s nuclear research through diplomatic means, various international agreements and the imposition of sanctions through UN resolutions seemed to be having some effect, but there were indications that weapons research had not stopped – In 2006, Iran was found to have a heavy water production plant but had not notified the International Atomic Energy Agency (IAEA). Heavy water can have a “dual use” purpose in either nuclear weapons production or for power production. To make matters worse, Iran did not permit full inspection of its facilities by the IAEA, something which all countries signed up to the NPT must allow.

Iran’s stance towards the international community changed somewhat in 2013 with the election of president Rouhani, thought to be more moderate than his predecessor Ahmadinejad. He requested the start of new negotiations with the international community, and even had direct talks with President Obama.

THE JCPOA

These new negotiations laid the foundation for the JCPOA and an interim agreement came into effect at the start of 2014 which allowed for increased inspections by the IAEA and the suspension of certain parts of its programme in return for relief from some sanctions. The IAEA issued a statement that Iran had complied with terms of the interim agreement which was reinforced by a statement on 5 March 2018 from the IAEA’s Director General, Yukio Amana, to the IAEA’s Board of Governors: “As of today, I can state that Iran is implementing its nuclear-related commitments …”; a conclusion supported by the Agency’s inspectors who spend some 3000 calendar days per year on the ground in Iran.

The JCPOA is quite a complex agreement, under which Iran has to reduce its stockpile of enriched uranium, limit any future enrichment to values not capable of producing nuclear weapons, limit uranium enrichment to one site, not build any new heavy water reactors, and adapt its existing one for peaceful purposes. Iran will also sign up to the Additional Protocol and submit to a comprehensive inspections regime by the IAEA which will involve some 150 inspectors. So long as Iran complies with the terms of the JCPOA, then various sanctions will be eased or lifted altogether.

The signing of the JCPOA was welcomed by virtually every country and international institution, although Israel remained critical. Iran’s fellow Middle East states saw it as bringing stability to the region. So what does President Trump have to be concerned about?

PRESIDENT TRUMP’S VIEW

Under US law the JCPOA is a non-binding agreement and has to have the approval of Congress following certification by the President. In his statement of 8th May 2018, President Trump said “It is clear to me that we cannot prevent an Iranian nuclear bomb under the decaying and rotten structure of the current agreement” and the deal is “defective at its core”. He further believes that Iran is a “sponsor of terror” and that there is a “very real threat of Iran’s nuclear breakout”; moreover, he linked Iran’s missile and other defence activities to the deal, something it was not designed to do. He is particularly concerned that much of the agreement is time-limited – around a decade or so for many of its provisions, but he wants it to be permanent.

INTERNATIONAL REACTION

Ahead of the 8th May statement, the position of the JCPOA’s counter signatories was that they remained committed to the deal, but their powers of persuasion were obviously non-existent. The UK Foreign Secretary, Boris Johnson said President Trump would be “throwing the baby out with the bathwater” if he went ahead with his decision; French President Macron Tweeted after the statement “France, Germany and the United Kingdom regret the US decision to get out of the Iranian nuclear deal …the international regime against nuclear proliferation is at stake.” UN Secretary General Antonio Guterres says he is “deeply concerned by the US decision to withdraw from Iran nuclear deal”, and calls on all other parties to fully abide by deal’s commitments.

THE US SCIENTISTS’ VIEWS

More criticism of the President’s position came from 90 American scientists in a letter published in October 2017 asking Congress to remain party to the agreement. They noted also that non-nuclear activities, not covered by the JCPOA, could be addressed separately and acknowledged Iran’s willingness to hold separate talks on its ballistic missile program. They point out that the IAEA’s system of safeguards under the Additional Protocol is the “strongest set … implemented by the IAEA”. They go on to say that additional “real-time” verification measures would be beneficial, not only in Iran, but in all non-nuclear weapon states where there is doubt about product use and that multinational control of enrichment plants would provide an extra level of security, citing the arrangements that URENCO, the European enrichment company.

FORMER GOVERNMENT OFFICIALS AND EXPERTS’ COUNTER VIEWS

A counter statement by the Foundation for Defense of Democracies (FDD) was also given in October 2017 which supported President Trump’s stance. It was signed by some 20 “former Government officials and experts” and included former IAEA Deputy Director General Olli Heinonen. It described the JCPOA “as one of the most highly deficient arms control accords in the history of American arms control diplomacy”. It went on to say that “We hope that the White House and Congress can come together to fix a fundamentally flawed agreement, curb Iran’s illicit activities, and end the nuclear blackmail imposed by the current JCPOA”.

WHAT NEXT?

Some observers believe that the US withdrawing from the JCPOA will mean Iran will continue to develop a nuclear weapons’ programme, however, technically, the JCPOA remains in force. Will it trigger a nuclear arms race in the Middle East? Although not officially recognised, it is well believed that Israel possesses over 40 nuclear warheads, on a par with India and Pakistan. Netanyahu fully supports President Trump’s decision, of course, giving his own assessment of Iran’s nuclear programme, saying “Iran lied”.

In March 2018 on a visit to the US Saudi Arabia’s Crown Prince Mohammed bin Salman said “… if Iran developed a nuclear bomb, we will follow suit as soon as possible”.

There will be plenty of commentary over the coming days and month. Decisions such as this have a tendency to implement the “law of unintended consequences”. We will monitor the situation and post further blogs on the issue.

For a PDF of this blog click here

Prospect Law is a multi-disciplinary practice with specialist expertise in the energy and environmental sectors with particular experience in the low carbon energy sector. The firm is made up of lawyers, engineers, surveyors and finance experts.
This article remains the copyright property of Prospect Law Ltd and Prospect Advisory Ltd and neither the article nor any part of it may be published or copied without the prior written permission of the directors of Prospect Law and Prospect Advisory.
This article is not intended to constitute legal or other professional advice and it should not be relied on in any way. For more information or assistance with a particular query please in the first instance contact the department paralegal Adam Mikula on 020 7947 5354 or by email on adm@prospectlaw.co.uk

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OIL & GAS: VOLATILITY – ATTENTION TO DETAIL – THE KEY TO SUSTAINABILITY, PART II

In the following series of articles Alex Bakhshov will examine the challenges that come with negotiating key legal and contractual terms and managing legal risks across infrastructure operations comprising major oil and gas projects (Projects) in developing oil and gas markets and in turn a means through which to mitigate the impact of inflated barrel production costs (Barrel Price) by Independent Oil Companies (IOC), Oil Field Service Providers (OFP) and other market participants seeking to make strategic decisions relating to foreign direct investment (FDI).

Introduction:

In the first part of this series Alex Bakhshov considered the common determinants and barriers for Independent Oil Companies (IOC), Oil Field Service Providers (OFP) and other market participants seeking to make strategic decisions relating to Foreign Direct Investment (FDI) in developing markets. In this second article Alex will focus on the barriers faced by IOC’s in sub – Saharan Africa (SSA), which presents its own unique set of challenges amongst developing markets. Alex will hope to demonstrate that by collaborating with domestic policy makers (Regulators), barriers to FDI can be overcome and sustainable business can be built through periods of oil price volatility.

Unfavourable Fiscal Terms

A frequent source of frustration for oil executives seeking to invest in developing markets and in particular in SSA are the unfavorable fiscal terms frequently encountered during periods of low oil prices; this coupled with inflated barrel production costs (Barrel Price) is often the primary barrier to FDI. Paul McDade, chief executive of Africa focused Tullow oil told the Africa Oil Week Conference in Cape Town (2017) that exploration license terms must be competitive to attract new investors to the region’s upstream.

This means governments and regulators being bold and flexible and allowing companies to make final investment decisions more quickly by improving fiscal terms that were in many cases initially agreed at greater than $100 per barrel,” he said. “At the end of the day capital goes where it’s welcome and that’s especially the case at $50 oil. If we like the play and we like the basin, but the terms don’t work, then we won’t be investing.

The reality is that resource rich dependent and developing economies are impacted negatively during low oil prices, triggering aggressive fiscal terms for investors; however this should serve as an impetus and incentive for collaboration for diversification of the economy and liberalization of the legal framework to allow full ownership of enterprises by foreigners and the proper protection of their property rights – which would have the added benefit of encouraging expatriates to save and invest locally. SSA remains behind the GCC states in diversification of economic initiatives (see further “Could low oil prices be an opportunity for the Middle East?”, World Economic Forum). So even where fiscal terms are unfavourable, there are opportunities for IOC’s to include the meaningful transfer of knowledge and technology as part of FDI by, amongst other initiatives, engaging with Local Content Requirements (LCR’s).

As was shown in Part 1 of this series, in considering FDI, frequently overlooked by the investment community and oil executives are the inherent legal risks in the misalignment between international contracts and those mandated under LCR’s; especially where the initial fiscal terms look attractive. Often these risks do not materialize until a contractual dispute, political upheaval including policy and legislative change or environmental crisis arises, which will often be long after significant capital has already been committed, further inflating Barrel Prices. Whilst developing markets are prone to these risks, these factors are rarely factored into the Barrel Price and therefore proactive procurement, contracting, governance and project management strategies must be implemented early on and revisited throughout the lifetime of the oil and gas project (Project), to minimize the impact on business disruption, health and safety or financial loss.

Varying Production Costs:

Investment in high oil and gas dependent developing countries, as has been indicated in relation to SSA, does not consistently attract FDI, as the components of Barrel Price can be inflated through higher capital costs, taxes, transportation costs, infrastructure unreliability and security costs. Risks of expropriation during periods of political instability and the imposition by some countries of a requirement of majority domestic ownership can be a significant deterrent to FDI (see further ‘On the Determinants of Foreign Direct Investment to Developing Countries: Is Africa Different?’ World Development Vol. 30, No. 1, pp. 107 to 119, 2002).

Oil and gas barrel production Cost, March 2016
Country Gross
taxes
Capital
spending
Production
costs
Admin
transport
Total
UK $0 $22.67 $17.36 $4.30 $44.33
Brazil $6.66 $16.09 $9.45 $2.80 $34.99
Nigeria $4.11 $13.10 $8.81 $2.97 $28.99
Venezuela $10.48 $6.66 $7.94 $2.54 $27.62
Canada $2.48 $9.69 $11.56 $2.92 $26.64
U.S. Shale $6.42 $7.56 $5.85 $3.52 $23.35
Norway $0.19 $13.76 $4.24 $3.12 $21.31
U.S. non-shale $5.03 $7.70 $5.15 $3.11 $20.99
Indonesia $1.55 $7.65 $6.87 $3.63 $19.71
Russia $8.44 $5.10 $2.98 $2.69 $19.21
Iraq $0.91 $5.03 $2.16 $2.47 $10.57
Iran $0 $4.48 $1.94 $2.67 $9.08
Saudi Arabia $0 $3.50 $3.00 $2.49 $8.98

Source: “Barrel Breakdown” Wall Street Journal, April 15, 2016.

Increased Costs: Nigeria & Angola

It is evident that in Nigeria, the total Barrel Price is significantly higher than most of the emerging markets largely due to higher capital and production costs. In times of low oil prices, Nigeria therefore does not attract FDI. These increased costs are due in part to lack of confidence in infrastructure and security concerns – most of the exploration activities now occur offshore, which attracts significant capital spending. Indeed, as indicated above the trend is that SSA countries attract less FDI than MENA or indeed other developing regions. This is troubling not only because of the significant oil reserves (Nigeria and Angola have amongst the highest proven reserves in the world) but because FDI is crucial to the region to help accelerate growth through technology, knowledge transfers, employment and infrastructure.

Pade Durotoye, chief executive of Nigerian independent Oando Energy Resources, has expressed frustration at the delay the company faced in exploration and production on its acreage because of unattractive terms.

One of the things we are trying to make the government understand and appreciate is that a higher government take of nothing is nothing,” he said at the Africa Oil Week conference in Cape Town (2017).

Future Reform:

These messages come at a critical time for the industry in the region, as governments rethink their hydrocarbons strategies at $50-60 oil. The continent’s two largest oil producers, Nigeria and Angola, are revamping their investment and legal frameworks for the oil and gas sector, and a plethora of other African states are keen to emulate the recent success of Senegal, Mauritania and Mozambique in kick-starting exploration and converting successful finds into concrete development plans.

Cote d’Ivoire, having just settled a protracted maritime border dispute with Ghana, has re-launched its efforts to encourage new exploration, offering redrawn blocks through direct negotiation with oil companies. Elsewhere on the continent, Namibia, Sierra Leone, Liberia and the Gambia are also promoting frontier offshore acreage. Onshore, Mali is also offering up blocks, hoping that investors will overlook the security risks posed by Islamist terrorism.

They will be keen to emulate countries such as Ghana, Mozambique and Senegal, which have managed to maintain exploration momentum during the industry downturn since Brent crude futures began to tumble in mid-2014.

In Part 3 of this series Alex Bakhshov will take a closer look at Mozambique, which has consistently attracted FDI, thus bucking the trend amongst SSA countries. Alex will take a close look at Mozambican Regulators’ approach to working in collaboration with IOC’s to develop its infrastructure and implement legal and social reform by working towards an innovative legal framework and diversification of its markets.

Alex Bakhshov is a commercial lawyer specialising in project and infrastructure work, having attained experience of major projects in Africa, Asia, the North Sea, South America and Australia. Alex has advised on mergers and acquisitions, joint ventures, construction, regulatory, contracting and procurement strategies, and possesses significant experience in construction, the marine sector, shipyard disputes, shipping (both wet and dry) and offshore Oil & Gas projects in the North Sea, West Africa and Brazil.

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 or assistance with a particular query please in the first instance contact the department paralegal 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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LIABILITY FOR CONTAMINATED FORMER LOCAL AUTHORITY SITES

Environmental Protection Act 1990

Part 2A of the Environmental Protection Act 1990 imposes a duty on enforcing authorities to require those responsible to remediate contaminated land, i.e. land designated as such which due to substances in it is causing or threatening significant harm or significant water pollution. Whether the ‘significant’ threshold has been reached falls to be determined in accordance with the Statutory Guidance issued under Part 2A (http://www.legislation.gov.uk/ukpga/1990/43/part/IIA).

The persons primarily responsible for remediating contaminated land under Part 2A are ‘Class A’ persons, i.e. those who caused or knowingly permitted the relevant substances to be present.  If no Class A persons remain in existence, liability falls on ‘Class B’ persons, i.e. those who are owners or occupiers at the time when the land is determined to be contaminated for the purposes of Part 2A.  If there is more than one Class A or Class B person, the Statutory Guidance sets out a number of tests designed to exclude from liability those considered less responsible.  If more than one liable person remains after the application of those tests, liability is apportioned in accordance with the Statutory Guidance.

A question has arisen in relation to the liability of a Class A entity which is dissolved by statute and replaced by another statutory body.  Does the successor take on the liability of its predecessor?  There are two issues.

  • First, should the successor be considered as a causer or knowing permitter simply because it has taken over the functions or business of its predecessor?
  • Secondly, does the predecessor have liability under Part 2A which passes to its successor under legislation abolishing the former and creating the latter?

The first question was answered with a resounding negative by the House of Lords (now replaced by the Supreme Court) in R  (National Grid Gas plc) v Environment Agency  [2007] (https://publications.parliament.uk/pa/ld200607/ldjudgmt/jd070627/grid-1.htm). National Grid Gas, the privatised successor company, did not cause or knowingly permit the presence of the contaminants. The land had been sold by its predecessors before the company was formed at the time of privatisation of the gas industry in 1986.  There was nothing in Part 2A which extended the categories of causers and knowing permitters to their successors.

Powys County Council v Price and Hardwick [2017] EWCA Civ 1113

The same issue arose in Powys County Council v Price and Hardwick [2017].  (http://www.bailii.org/ew/cases/EWCA/Civ/2017/1133.html)

A Welsh local authority had operated a landfill over a culverted watercourse which eventually resulted in river pollution. The land had been sold after landfilling stopped and was subsequently designated as contaminated land under Part 2A.  Following statutory reorganisation of the Welsh local authorities, it was widely assumed that the new authorities would simply step into the shoes of their predecessors and assume their liability as causers of the contamination.  The Court of Appeal followed the National Grid decision and held that was not the case.  The emphasis in Part 2A is on the actual polluter: the person who caused or knowingly permitted the pollution.

The second question was whether Part 2A liability passed from the predecessor to the successor body under the provisions of the relevant institutional restructuring legislation. Under the Gas Act 1986 and earlier Gas Acts considered in the National Grid case, liabilities to which the predecessor was subject “immediately before” the statutory transfer date passed to the successor.  The statutory transfer date was 24 August 1986, whereas Part 2A was inserted into the Environmental Protection Act 1990 by the Environment Act 1995 (https://www.legislation.gov.uk/ukpga/1995/25/contents) and only came into force on 1 April 2000 in England and 15 September 2001 in Wales.

In National Grid the House of Lords held that liabilities created by statute in 1995 did not exist immediately before the transfer date in 1986 and therefore could not have been transferred to National Grid Gas as the successor body.

Distinguishing Powys from National Grid:

The position in the Powys case was different in two respects.  First, Article 4 of the Local Government Re-organisation (Wales) (Property etc) Order 1996 (http://www.legislation.gov.uk/cy/uksi/1996/532/body/made/data.xht?wrap=true) simply stated that the ‘liabilities of the old authority shall …. vest in [the]  successor authority’.  However, the Court of Appeal considered that the omission of words such as ‘immediately before’ made no difference.  Following the reasoning of the House of Lords in National Grid, Lord Justice Lloyd Jones held that ‘liabilities’ refers to those to which the predecessor was subject prior to the transfer.  The words ‘immediately before’ merely emphasise that conclusion.  If Parliament intended to transfer liabilities arising subsequently, clear words would be required to achieve that result.  For example, under transfer of liability schemes made under the Water Act 1989 (https://www.legislation.gov.uk/ukpga/1989/15/contents) a body to which liabilities are transferred is to be treated as the same person in law as the authority from which they are  transferred.  That wording has the effect of transferring to the successor liabilities not yet in existence at the time of the transfer.

Secondly, the statutory transfer date under the Welsh local government reorganisation legislation fell after the insertion of Part 2A into the Environmental Protection Act in 1995 but before it came into force in Wales in 2001.  The distinction was unimportant to the decision in National Grid and so, perhaps unsurprisingly, the House of Lords focused on the earlier date.  However, in Powys it was held that the date when the Part 2A  legislation came into force was the relevant time.  The Court of Appeal stated that if Part 2A had been in force on the statutory transfer date, the predecessor authority would have been subject to a contingent liability which passed to the successor authority on that date.  As Part 2A was not then in force, there was no liability under that legislation, contingent or otherwise, which was capable of being passed to the successor.                                                                                                                     

Points to Note

  1. Since there was no Class A person in existence (the predecessor local authority having been dissolved under the local government re-organisation legislation) liability fell on Class B persons, the current owners and occupiers of the land, Mr Price and Mrs Hardwick.  From the perspective of owners of contaminated former local authority land the effect of such legislation may be to eliminate the only other party who may be solely or partly liable for the costs of remediation.  If, unlike Mr Price and Mrs Hardwick, the current owner is a Class A  knowing permitter (e.g. due to failure to remediate when it should have been clear that remediation was necessary) that owner could be made to shoulder the full liability, whereas Part 2A liability may have been shared with the predecessor local authority (if it were still in existence)  under the apportionment provisions of the Statutory Guidance unless that predecessor authority had been excluded from liability under the exclusion tests.
  2. Although not mentioned by the Court of Appeal in Powys, the Part 2A Statutory Guidance enables the enforcing authorities to waive or reduce the liability of both Class A and Class B persons in certain circumstances such as hardship or unfairness to the liable party.  That discretion is exercised in suitable cases.
  3. In cases of statutory reorganisation the precise statutory wording is critical in determining whether Part 2A liability has passed to the successor.  If liabilities are merely expressed to be passed to the successor, Part 2A liability only passes if Part2A came into force before the statutory transfer date.  On the other hand, if the liability transfer legislation states that the successor body is to be treated as the same person as the predecessor, the successor would assume the predecessor’s Part2A liability even if Part 2A came into force after the statutory transfer date.
  4. The Court of Appeal noted that contingent liabilities of the predecessor under existing law (e.g. breaches of a duty of care which had not yet resulted in damage) would have passed to the successor at the statutory transfer date.  It follows that in the Powys case if neighbouring landowners claimed compensation because pollution from the former landfill had migrated to their land, the predecessor local authority’s contingent liability would pass to the successor.  The latter would therefore be liable when the neighbours suffered damage even if that occurred many years after the landfill operation had ceased.
  5. Owners of contaminated former local authority sites are well advised to check their potential liabilities and whether they have been affected  by local government reorganisation legislation. The provisions of the sale contract should also be considered as these may be worded to trigger a transfer of Part 2A liability to the buyer under the exclusion tests in the Statutory Guidance, thereby excluding the seller authority from liability. The issues involved in transferring Part 2A liability and other contaminated land liabilities are complex and require detailed advice.

3rd January 2018, Prospect Law Ltd

Andrew Waite is a solicitor and specialist in environmental, health and safety and public law, advising on regulatory and liability issues for a broad range of industries.  He defends prosecutions for breaches of environmental and health and safety legislation, deals with regulatory appeals, judicial reviews 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 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.

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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.

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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