Global oil & gas Oil price volatility – risks and opportunities in 2015

Introduction During the second half of 2014, and at the start of 2015, we have seen increasing global, and indeed market, instability across a wide range of commodities. Crude oil producers have been particularly vulnerable to ‘the new instability’, caught in a perfect storm of relative decreasing demand, increasing production volumes and changing geopolitical factors. In the short term at least, a straw poll of commentators doesn’t identify significant upward pressure on crude oil prices, hinting that the current trend for lower crude oil prices is set to be with us for a while. In the following series of articles, written over the course of the first few months of 2015, Clyde & Co explores the implications of the recent dramatic fall in the price of crude oil. We focus in on the impact for the global oil & gas industry as well as looking at the response from particular markets, regions or countries, taking in for example how price fluctuations in commodity markets interplay with the oil market, or the impact on counterparties as companies vulnerable to a slump in crude prices edge closer to default.

Contents Impacts on long term supply and service agreements 

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How has the drop in oil prices affected other commodities?

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Legal issues arising in the E&P sector

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JV Counterparty distress

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Offshore oil storage - legal implications

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Global employment issues

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How will declining oil prices impact on the UK’s renewables sector?

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Regional focus – Impacts on the MENA renewable and petrochemical market

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Directors’ Liabilities

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Dedicated to the oil & gas industry 

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About Clyde & Co 

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Impacts on long term supply and service agreements Written by

Ben Knowles Partner, London

T: +44 20 7876 4732 E: [email protected]

We are all wrestling with the ramifications of a volatile oil price and, as lawyers, we are starting to see the early impacts of this new paradigm. Immediate, direct effects such as the cancellation of projects in the oil & gas sector due to economic unviability, and layoffs in areas with higher production costs such as the North Sea, are already starting to seep into the wider economy, and their final impact is still unknown. Questions, such as how net crude importing nations might use the additional funds now in their coffers, and how net exporters such as Venezuela, Nigeria and Russia can fill the income gap, are now at the forefront of global attention. What is certain is that there will be winners and losers, and adjusting quickly to the new climate will be key to survival and success.

Introduction to contractual termination issues Should a party find themselves facing a contractual termination issue there are some basic points to consider at the outset which may help to put you in the best position possible. These include: Conduct: Depending on the specific circumstances relating to the potential termination, it may be important not to delay unnecessarily in terminating, or to engage in conduct which could be seen as affirmation of the contact. Conversely, in certain circumstances parties may wish to avoid any suggestion of terminating the contract in order to preserve the maximum number of heads of claim. Exposure: Clearly different factors come into play when looking at an extensive framework contract as opposed to a short term single contract. For example, in respect of production sales, there may be hedges in place which will reduce or increase losses upon termination. Legal rights: If you are the potential terminating party, a close analysis of the termination provisions in your contracts will be required. There may be force majeure provisions, or certain circumstances under the contract in which you may terminate on a legitimate basis.

Contract formalities: Irrespective of which side of the coin you are on, it is important to consider if there are any particular formalities in the contract in respect of termination. For example, any time limits or notification requirements. Potential non contractual rights: It is also worth considering whether there are any legal rights under the applicable law of the contract that improve your position. For example, enhanced statutory force majeure rights. Protection/mitigation: Assuming your contract has been terminated, are there any steps you should take to protect your position. For example, registering a protest or mitigating your losses by terminating ongoing arrangements/arranging alternative suppliers. The bottom line is that each case will turn on its individual facts. However, a prompt response to a termination situation, and a speedy analysis of the contractual position, may ultimately save time and money.

Impact on short and long term agreements Our experience is that a landscape such as the current one can create great pressure for principals and suppliers in relation to both short and long term agreements, and that circumstances may arise in which organisations throughout the supply chain take a commercial decision to walk away from contracts as a result of market conditions. This is particularly pertinent in the context of longer term agreements including rig agreements, Production Sharing Agreements (PSAs), service arrangements and sales/ supply contracts. Decisions to walk away can occur when situations change quickly and unexpectedly, with many parties currently revaluating projects, and in some cases walking away without forewarning.

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Such circumstances typically lead to a proliferation of legal disputes between parties and our indications are indeed that the volume of disputes between parties is currently increasing. By way of introduction to this series of articles, we discuss below, at a high level, some basic measures parties should consider to assist themselves should contractual termination issues, such as those discussed in this article, arise.

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How has the drop in oil prices affected other commodities? Written by

Philip Prowse Partner, London

T: +44 20 7876 4961 E: [email protected]

The effects of the dramatic drop in the price of both Ice March Brent, the international oil marker, and its US counterpart Nymex March West Texas Intermediate, have been widespread. This is impacting not only the oil services industry, where many firms have cut their capital budgets as well as jobs, but also a number of markets across the world. The commodities market, in particular, has been widely affected with the prices of metals such as copper, lead and nickel dropping, albeit not as dramatically as oil, and the price of gold increasing. In passing, it is worth noting that the death of King Abdullah in January 2015 prompted some investors to bet on a change in strategy as a result of the change in the leadership of Saudi Arabia, OPEC’s largest producer and de facto leader, with Crown Prince Salman succeeding King Abdullah. However, many analysts expect King Salman and Ali al-Naimi, Saudi Arabia’s oil minister, to stand by the existing Saudi oil policy, at least in the near term. That is, to allow market forces to determine the oil price and press ahead with unrestrained production of crude in order to eclipse more marginal producers and to not risk losing market share, despite the effects that this has had on the price of oil.

How has the drop in oil prices affected other commodities? The sharp fall in oil prices amid deteriorating sentiment over the global economy has made investors weary of investing in other commodities.

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Copper, in particular, has been hit very hard, slumping to its lowest price levels in nearly six years. This was triggered by aggressive selling by Chinese hedge funds earlier this month when the market was on the edge because of the collapse in the oil price and when physical demand in China was weak because of the approaching lunar New Year holiday. Other metals have also taken a hit, with nickel and lead experiencing recent sharp decreases. As the price of oil has dropped, gold, on the other hand, has experienced its highest price level since August 2014 as many investors have sought to invest in the market to park their capital. With the Euro falling to an 11 year low as a result of a number of factors including the Swiss National Bank’s decision to decouple from the Euro and the European Central Bank’s quantitative easing measures, gold has risen very quickly.

On top of a growing trend for banks to dispose of their commodities businesses, there is a debate whether banks will continue to finance trading in commodities. Oil, at least in the near future, is likely to provide a low return with most commentators thinking that the price will not rise substantially for the foreseeable future, with some even going so as far as stating that the price will fall as low as USD20 per barrel. Therefore, the incentive for banks to finance this particular commodity would appear to have fallen away. This could see a space open for non-bank lenders to come into the market and play a much more active role in the financing of commodities. These entities are generally subject to less regulation and have access to a more diverse set of methods to inject capital into financings.

Impact on existing contracts In the oil market, many, if not most participants will enter into hedging contracts against a price fluctuation. However, this is often a hedge against a rise in the oil price and some participants will, as a result of the current conditions, have found that they have been asked to make margin payments to hedge counterparties as they are ‘out of the money’ on the hedging contract.

Exit options? Parties may find it difficult to remove themselves from their existing commodities contracts. Force Majeure: A force majeure clause allows one party who has been subject to a pre-defined event to suspend performance under the contract, or , in a worst case scenario, allow one or both parties to terminate the contract. The key point to note is that performance by the affected party should be rendered impossible to perform (sometimes being severely hindered is also considered to constitute force majeure). Some parties may look to rely on this provision, however it is unlikely that the fall in oil prices will constitute a force majeure event under contracts.

Material Adverse Change clauses: There is a possibility that parties could look to material adverse change clauses in their agreements as a way of terminating their contracts. However, these clauses are usually drafted to concern the state of the individual contract participants (e.g. a party’s credit rating) rather than market realities. These provisions are also notoriously difficult to rely on in the event of a termination. Of course, if a party’s credit rating, for example, were to be affected because of the fall in oil prices, then this could provide an option for the other party to terminate under this type of provision.

What can parties do to counter the drop in oil prices? It may be possible for parties to include, in future contracts, a clause which is effectively a ‘hedge’ to be triggered by a pre-determined event (for instance a defined rise or fall in the oil price, e.g. if oil drops below USDX per barrel). This could give parties the ability to re-price the contract in this event, to ensure the contract remains economically viable, or at least to be obliged to enter into good faith negotiations around re-pricing. Depending on the level of bargaining power between the parties, it may even be possible to incorporate such a fluctuation as a termination event. Existing contracts could also be reviewed to see if there is the possibility of amending them to include such a clause, but re-negotiating an existing contract which does not have a contractual mechanism for this already built in would seem unlikely. The full impact and the duration of the drop in oil prices remains to be seen; but what is certain is that this is a worrying time for the commodities market. Parties will have to consider the terms of their existing contracts as well as continuing to consider ways to mitigate risk when embarking on transactions in the future. This could include a renewed reliance upon derivatives as a way of protecting against price and foreign exchange risk.

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Legal issues arising in the E&P sector Written by

and

Philip Mace

Michael Wachtel

T: +44 20 7876 4208 E: [email protected]

T: +44 20 7876 4216 E: [email protected]

Partner, London

Partner, London

In recent years, Africa and other developing markets have been a major focus for a significant number of small/mid cap E&P companies. However, with oil prices at their lowest for over five years, and indications that they may stay at this level for some time, E&P companies and the governments of the countries where they conduct their exploration and production activities are now assessing their options. For small/mid cap players the prospects for raising substantial capital either through debt or equity financing are extremely tough or non-existent. At the same time, E&P companies are bound by the work commitments agreed to in their contracts with host governments (in most cases production sharing contracts (PSCs)), and perhaps budgets approved before the extent of the price fall was known. Unsurprisingly, insolvency and consolidation in the sector is now occurring as companies face the possibility of not meeting the PSC conditions and the prospect of their subsequent termination and forfeiture. From the government’s perspective it could be the case that by causing the incumbent to forfeit its PSC or licence, the government would find itself with a block which no new entrant is willing to take on, or for which potential new entrants request reduced work commitments and extended

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exploration periods. In short, the government could be swapping delays on the part of the existing PSC holder for potentially longer delays and reduced work commitments. Certainly for the duration of any gap, the government will not be paid any applicable rental fees or contributions to their training and development budgets as required under the PSC. These payments are often important sources of hard currency particularly in countries where oil and gas production has yet to start. Also companies that are forced to exit will lay off all locally hired staff and contractors and the resulting unemployment may not be short-lived with the attendant political cost and implications. As it is not necessarily straightforward for a government to enforce its rights and achieve a quick and easy clean break, there may be an opportunity for the renegotiation of commitments.

Resulting legal issues: 1. Limitations on, or consents required due to, a change of control, asset disposal or the creation of security: This is an issue applicable to both debt and equity financing depending on the structure and the creation and/or enforcement of any security. 2. Solvency: Is the company insolvent either under legislative definitions or as defined by any contractual undertakings? Have any prior covenants been breached as a result? Do breaches cause cross defaults under any other agreements and what are the implications? 3. Employment issues: Are redundancies required? What is the process? How can terms of employment be amended to minimise redundancies? Do employees automatically transfer to the buyer of an asset, and if so, what are the consequences?

Fundamentally, oil companies and investors will be assessing the ongoing viability of financing their investments. Whether the decision is made to raise equity, debt, a combination of the two, manage the portfolio or renegotiate contracts or commitments, the considerations highlighted above will be prominent in the thinking of all company directors and senior managers. To make the best possible decisions, expert legal advice will be required. Our lawyers are experts in their chosen practice areas who focus their practices in the oil & gas sector. They have previously dealt with all the issues now faced by companies, shareholders and governments in the oil & gas sector and are therefore uniquely placed to provide cost effective, focused and value-adding legal advice.

4. Corporate and directorship issues: What are the duties of directors? What is their personal liability? Will any personal liability of directors be covered by D&O insurance? What corporate authorisations are required for transactions and/or commercial renegotiations? 5. Contractual and commercial issues: How can you be sure that renegotiation of contractual terms is binding and effective? What local approvals are required? Are there any regulatory issues, for example, is competitive retendering required? Does a sustained drop in the oil price constitute, or could it lead to, an event of force majeure, and if so, would any relief be available as a result? 6. Litigation: Is any protection available through investment treaties? How can the chances of a successful arbitration litigation be maximised? What is the best way of trying to ensure that enforcement of an award or judgement is achieved? Does litigation or the threat of it cause any agreement warranties to be breached and if so what are the consequences and how are they most effectively mitigated?

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JV Counterparty distress Written by

Stewart Perry Partner, London

T: +44 20 7876 4338 E: [email protected]

The slide and volatility in the oil price over the past few months has been dramatic and whilst many companies will be well positioned to weather the current climate, it has already become clear that there are some players in the industry for whom insolvency is a very real risk. An important issue to consider is the situation where one party to a Joint Operating Agreement (JOA) enters into an insolvency process. Although all JOAs are tailored for the relevant asset, certain standard clauses are prevalent throughout the market; we consider some examples of these below by reference to the insolvency of an Operator and a Non-Operator. Operator insolvency Do the other parties have the ability to replace the Operator? Some standard clauses only use the undefined term “insolvency” as a trigger to replace an Operator. This has a number of meanings (eg cash-flow insolvency or balance sheet insolvency) and there have been many expensive court battles on what this term means. Ideally, therefore, the parties would rely on other triggers. Some clauses will describe insolvency processes. However, one we recently reviewed did not include Administration or Chapter 11 proceedings, and recent case law would suggest their omission would mean such a process would not trigger a replacement right. Also, what if the Operator enters a process specific to its home jurisdiction? Is the term, for instance, defined to include “or other similar processes wherever situated”? Also, would the insolvency of a parent company trigger a replacement? This will be particularly important if the Operator relies on its parent for funding. The change of control provisions in a JOA we recently reviewed would not be triggered by the liquidation of a parent.

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If a replacement is possible, what assets will the successor Operator be able to control? The ability of a court to recognise a distinction between the physical possessor or named owner of an asset, and the beneficial owners, varies around the world. English law, for instance, would recognise the ability of the Operator to hold money on trust for the other parties, whilst some other continental European countries would not. If the Operator is validly holding Joint Property on trust for the parties, it may be possible to ensure the successor takes control of them. However, if no valid trust is created, or the local jurisdiction does not recognise trusts, the NonOperators may be left with only a contractual claim against an insolvent entity (which is likely to be worthless). It may therefore be worthwhile ensuring Joint Property is held in a trust-friendly jurisdiction. This is perhaps easiest to arrange for the Joint Account. However, the parties should also ensure the Joint Account is operated in such a way that the trust would be given effect. In England, for instance, if the Operator was permitted to comingle the Joint Account funds with his own, this may defeat the trust.

What would be the position of a successor Operator in relation to the continuation of any dedicated work force? In some jurisdictions, including England, certain insolvency processes automatically terminate contracts of employment. In addition, some jurisdictions (including any member state of the EU) have laws to protect employees such that any successor may also be considered liable for the predecessor’s employment contracts and liabilities.

What if the JOA includes a provision for the purchase of the defaulter’s interest? In England, if the non-defaulting parties wish to (1) pay less than the market value, or (2) set-off against the market value sums due from the defaulting party, they could be open to challenge as preferences, transaction at an undervalue or contrary to the anti-deprivation principle and advice should be sought.

What if the JOA specifically requires the Operator to enter into contracts such that only the Operator can be liable to the contractor? This may work both ways, such that the contractor has no liability to the other parties. What then if the Operator enters liquidation and the contract contains a nonassignment clause? The Non-Operators may be left with no action against the contractor and may not even be able to rely / sue on that contractor’s insurance policy. The contracts may also be terminable by the counterparty on the Operator’s insolvency.

What risk does this pose to the Operator? Operators should also be concerned that the value of any indemnity provided by the insolvent Non-Operator is now likely to be worthless. Any clauses seeking to defeat setoff rights of the insolvent entity are also likely to become redundant as statutorily imposed insolvency set-off automatically takes effect.

Whatever happens to the Operator, the other parties will want to ensure any insurance policies are continued. If a policy is nearing its renewal date this may lend urgency to the appointment of a successor.

Non-Operator insolvency What triggers your rights against an insolvent NonOperator? In a JOA we recently considered, the trigger for default was only non-payment of sums due. What if nothing is due and that party had a blocking right for any future works? The liquidation of that party could effectively stall the project.

An insolvent counterparty has the potential to be extremely problematic if not handled correctly. However, it also provides a possible opportunity to acquire the full rights to a strategic asset. The primary considerations for any JOA partner should be to ensure the documents provide for a rapid and cost free replacement of any distressed Operator and that the continuing JOA partners are given the ability to continue the project if one of its members fails, including the ability to take all the future benefit. Consideration should be given now to any concerns as to the availability of triggers and the location of Joint Property.

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Offshore oil storage - legal implications Written by

Tracey Chippendale-Holmes Senior Associate, London

T: +44 20 7876 4982 E: [email protected]

Tanker owners are happy. VLCCs and Suezmaxes are generating strong cash flows and charterers are rushing to procure tonnage in an increasingly tight market. Commentators estimate that 40-50 older VLCCs have been commissioned on long-term charters to store crude. Are there any legal concerns with tankers being used for floating storage? Tanker owners see less risk in their tankers sitting stationary than sailing the high seas, but need to ask where they will anchor, for how long and whether this changes the applicable regulatory regime. If a ‘storage tanker’ is actually a floating storage unit (FSU), there is increased permitting required and a reduced ability to limit liability under the International Convention on Civil Liability for Oil Pollution Damage. While the Convention imposes strict liability for pollution damage on the Owner, it does allow for this liability to be limited, absent actual fault of the Owner. This reduction in liability does not apply to FSUs though. Owners will need to know up front where the tanker will sit. This is for maintenance and staff planning even if it is not a concern to the insurers. There are obligations under Flag and Class for the Owner to fulfil, plus the requirements of the Hague or Hague-Visby Rules and the law of the relevant coastal states. Looking through the Tankers Fixtures List of the Lloyd’s List on the day of writing, 25 VLCCs and Suezmaxes were chartered, with two thirds of the VLCCs taken by Unipec for China with Reliance, oil majors and traders accounting for the next. At the recent Marine Money, London Ship Finance Forum, it was reported that Chinese shippers were shopping for several VLCCs on 2 year charters after concluding an agreement with Russian sellers desperate for cash as the sanctions take hold.

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Where in the World...? For the sovereign charterers, it makes sense to anchor close to home. The three big risks facing tankers in parts of Asia are piracy, weather and terrorism. Owners have the technology and systems to look out for all three but may face reduced control so far from port. Good intelligence is given by the live IMB Piracy and Armed Robbery Map and there may be metocean data available for the area. It is this which will inform the tanker requirements, from global strength of the hull to structural design of both hull and topsides to withstand fatigue cracks. If there is a disaster, the Owner will be fully liable for a vessel failure which results from the strain of standing too long at sea. Of concern is not only the financial liability, but also the environmental damage that will ensue and the potential for loss of life.

Wherever located, the tankers will need space to move in strong winds and currents. With almost all tankers being double-hulled now, they are not as stable in strong currents. Movement of the crude in ballast and cargo tanks can cause the tanker to sway suddenly and, in addition, there may be leakage from the inner layer. Other seas are off limits as they are Special Areas listed in MARPOL Annex 1 or are part of the seven main transit ‘chokepoints’ for crude oil. These are obvious targets for pirates and terrorists, as well as the risk of collisions and spills. Some charterers choose much quieter locations as we saw from recent attempts to work around Iranian sanctions. The ‘storage tankers’ were well hidden in the South China Sea. Not to the extent of the United Kalavryta which disappeared from radar in the Gulf of Mexico for three days in Summer 2014 when the transponder was turned off (to help it hide from a legal arrest). It sat completely invisible with a million barrels of crude even from informed Texan coastguards.

The Charter allocation of duties

–– The Owners will usually define the capacity of the tanker to perform as contracted in ‘good weather’. It must still be capable of satisfying the Vessel requirements set out in the charter and be in every way fit for the service contracted –– The nature and extent of the Owner’s obligation to maintain depends on the exact wording agreed by the parties to the charter. Additional attention is required if the tanker is to sit in warm seas as the marine growth will undermine performance of the vessel –– Due diligence and reasonable care in cleaning the hold and tanks will be both an express and implied obligation of the Owner. The Shoko Maru explosion was caused by a crew member cleaning paint off the deck when a little crude was remaining –– Responsibility for cargo stowage frequently sits with the Owner but the charterer may accept this liability to obtain its choice of vessel and location. The Oil Majors (led by Shell) who are seen chartering the most VLCCs, perhaps for storage, are more amenable to this

Worst case

So are Owners using their negotiating strength to pass the additional vessel and environmental risks to the charterers? This still leaves the Owner with the scheduling burden of dry docking, SIRE inspections and Class surveys. Modification to the vessel and additional legal documentation may be required to ensure the vessel is in every way fit for long term storage and MARPOL compliant.

If the tanker becomes damaged or new regulations are adopted which impact on the ability of the tanker to continue as a ‘storage tanker’, this may be a ‘frustrating’ event (under English law) and may mean that any advance hire paid will be repayable by the Owner. A claim to the insurer for ‘lay-up’ will not be possible because the tanker has been carrying crude.

Charter forms have not yet evolved to reflect the different consequences of a long anchorage at sea. Clause 4 of Shelltime 4 does not require a charterer to indicate how many voyages the tanker will undertake or whether it will be stationary. Relevant charter considerations remain:

And if there is an explosion, the Owner will look first to the insurance taken out in accordance with the International Convention on Civil Liability for Oil Pollution Damage. This is an amount equal to the Owner’s total prescribed liability according to the tanker’s gross tonnage. Even the amount applicable to VLCCs of up to 320,000 GT will pale in comparison with the likely third party claims though.

–– The continuing duty to employ the tanker at safe ports and within trading limits. The Owner may object to instructions which take the vessel beyond trading limits and expose the vessel to increased risks. The liability for this will sit with the charterer even if the additional insurance premiums are borne by them, because of the safe port obligation

In the haste to sign up another charterer and dust off another underutilized VLCC, Owners will be asking where and for how long the tanker will be a storage unit and how the Owner will reconcile that with its international legal and environmental obligations.

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Global employment issues Written by

and

Heidi Watson

Sara Khoja

T: +44 20 7876 4480 E: [email protected]

T: +971 4 384 4689 E: [email protected]

Partner, London

Partner, Dubai

Oil & gas layoffs have been grabbing the headlines in recent months following the slump in oil price. Shocking numbers have been bandied about by journalists billing this issue as one of the most damaging outcomes of the sector’s current market position. A recent Bloomberg report suggested over 100,000 job losses have flowed from the crisis globally, with key oil & gas hubs around the world being hit hardest with high profile announcements being made in almost every region. Whilst these staff cuts are being attributed to the falling oil price, the headlines mask a more difficult underlying issue which has been slowly building across the industry over recent years and was likely to have led to a proportion of the job cuts we are now seeing. Producers have long been looking at the rising cost of production and acknowledging that operations need to be restructured to counteract a real risk to profitability. Restructuring was therefore already in the pipeline across the sector and, along with the natural conclusion of major projects and the scaling back of new ones, accounts for a proportion of the cuts this year. However, it is fair to say that the worst is likely not over yet as we see the impact of the oil price slump trickling down into oilfield services companies which continue to announce job cuts across the globe. The numbers also do not take into account the effect of redeployment within businesses which are not picked up by the headlines. Businesses are looking at ways to avoid

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redundancies including adjusting rotas and shift patterns, although these proposals have encountered staunch opposition from unions. Other measures include the re-examination of the role of consultants in the sector as well as the use of mobile employees, considering reduced hours and down-manning offshore as well as contract days reductions. These measures will undoubtedly impact the overall number of job cuts in real terms, which are likely to be rather less than the numbers caught by the headlines.

The danger, as always, is balancing the benefits of realizing short term savings against losing key skills which will be difficult to get back into the business once markets recover. Prior to this current cycle of falling prices, the industry faced a skills shortage with a lack of young entrants and a retiring professional base. Mercer’s Global Talent Forecast (released in 2014), found that the industry currently has a global shortage of petroleum engineers with a world-wide shortage of roughly 22,000 forecasted for 2017. Mercer research indicates time-to-proficiency for a petroleum engineer can take between 20 and 30 years. Whilst there are a number of initiatives across the sector to attract and retain new talent, filling this skills gap remains a challenge. In some regions this is compounded by local issues. By way of example, the focus within many Middle Eastern countries on developing and promoting the local workforce could also mean that it is much harder or impossible to get key staff back in country when demand increases, with Middle Eastern states imposing rules around the hire of local staff over ex-pats.

We can expect the headlines to continue to present a picture of large scale job losses across the sector well into 2015. However, the industry will ultimately be looking to create an efficient business model which will ensure it is able, and has the manpower skills in place, to respond to demand when the oil price inevitably recovers. Businesses will be looking hard at whether restructuring can provide this solution, and care will be needed when planning such projects particularly where the restructuring crosses borders, to ensure local legal requirements are complied with during the process. Planning is the key here to ensure that a consistent and joined up message is agreed before announcements are made to staff. This means engaging with advisers at an early stage so that regional variation in process can be factored into the planning. In terms of ensuring key skills are retained, finding innovative ways to avoid redundancies, such as sabbaticals, reduced hours and adjusting shift patterns, is in everyone’s best interests. There is a bumpy road head but no doubt all within the sector will be hoping that the right balance has been struck to weather this storm and come out fighting on the other side.

Operators within the industry are in the medium to long term, likely to focus increasingly on growth of operations in the Far East and the Asia Pacific regions as Japan looks to alternative energy sources to its discredited nuclear programme and with consumption in India and China expected to double. New roles will become increasingly available in these regions which will go some way to limit the impact of job losses in other regions for the internationally mobile workforce.

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How will declining oil prices impact on the UK’s renewables sector? Written by

and

Clare Hatcher

Brett Hartley

T: +44 20 7876 4863 E: [email protected]

T: +44 20 7876 4860 E: [email protected]

Partner, London

Senior Associate, London

The dramatic fall in global oil prices and its impact on the UK renewables sector should be considered in the context of existing developments in the electricity market. Coinciding with the collapse of oil prices and industry concern over the long-term viability of the UK’s North Sea oil and gas sector, the UK Government has rolled out its policy on electricity market reform (EMR), which it has framed as the “biggest reform to the electricity sector since its privatisation”. Two critical objectives of EMR are security of electricity supply via the new Capacity Market mechanism (aimed at keeping the lights on during peak demand) and decarbonisation via the new feed-in-tariff Contracts for Differences (CFD) regime (a mechanism for subsidising renewables through competitive auctions). The Capacity Market and the CFD regime represent a classic tension between the security that flows from carbon-based generation (primarily coal and gas in the UK) and the decarbonisation benefits flowing from evermore competitive renewables such as wind and solar, all of which are, in reality, reliant on government subsidies and political support to survive. So, what, if anything, does such a dramatic fall in global oil prices mean for the burgeoning renewables sector in the UK? Will a long term drop in oil prices, together with a trailing drop in European natural gas prices, undermine momentum behind the UK’s policy on decarbonisation and market reform? The first factor to note is that unlike some other regions of the world, oil makes up very little of the generation mix for electricity in the UK – less than 1% - with gas being the primary (cleaner) substitute. As a result, oil does not compete with renewables such as wind or solar for electricity generation. Instead, its primary use is in the transport sector, where it remains dominant and has a direct impact on the consumer wallet at the pump or

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of competition and economies of scale which have driven down costs. Electricity generated from wind and solar is now highly competitive with carbon-based sources and a significantly cheaper source of electricity generation than diesel, even at oil’s record low prices. Despite the continued need for government subsidy, the renewables sector is now far more robust, price competitive and structurally embedded in the energy mix than in the 1980s and 90s when technologies such as solar suffered as a result of declining oil prices A third factor is the considerable political and structural momentum behind renewables and decarbonisation. The UK is committed to its carbon reduction targets at the national and EU level, commitments which should remain largely unaffected by declining oil prices, whichever party is in power after the May general election. Of course, it is difficult to predict how oil prices may affect decisions at the United Nations Climate Change Conference in Paris this coming December, which has as an objective a legally binding and global agreement on climate change. Oil rich nations, particularly those currently marginalised by broader geo-political events, such as Russia, are unlikely to be interested in the shift away from fossil fuels.

indirectly on the supermarket shelf with transport costs reflected in the price of goods. Oil does, however, compete with plant derived biofuels such a bioethanol, which may start to look like a more expensive option in the fuel mix if oil prices remain low. The recent ‘temporary’ closing of the Ensus biofuel factory in Teesside is an example of how the drop in oil prices and the corresponding drop in bioethanol prices can impact the sector. Yet even in this example, the reasons for closure are more complex. The factory’s owners have stated that rather than declining oil prices, the most significant contributing factor for the closure was continuing uncertainty at the EU level over limitations on the amount of food-based biofuels that can contribute to the EU’s objective of achieving 10% of its transport fuels from renewables by 2020.1 The biofuel sector is therefore exposed to risk from falling oil prices, but other unrelated factors are clearly very relevant in how such a drop will ultimately affect biofuels. The second factor to consider is that when oil prices significantly declined in the past, the renewables sector was still in its developmental infancy, lacking the current levels

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In our view, investment in proven renewables technology is likely to continue largely unaffected by declining oil prices in the short to medium term, although biofuels are exposed. Cheaper long-term gas would pose some threat in the UK, but perhaps only a minor one given green policy commitments and the considerable foothold wind and solar already have in the electricity generation sector. Gas has a clear and ongoing role to play for the foreseeable future in the UK’s energy mix, and was, for example, the dominant winner in the Capacity Market auction with the majority of capacity contracts going to combined cycle gas turbine plants given the large-scale certainty of supply they can deliver. Arguably, cheaper gas could reduce political will and support for nascent renewable technologies, such as tidal power, given the need for government subsidies and political support if these technologies are to prove their efficacy and competitiveness in the UK’s energy mix – but the jury is out on this. Notably, some commentators have suggested that the question should be reversed and we should look at how the rise of renewables has contributed to the decline in oil prices, rather than on how declining oil prices will affect renewables. This would be difficult to quantify, and we may have reached a tipping point where renewables are immune to a long-term drop in the oil price whether or not renewables have contributed to that very decline. Despite the collapse in the oil price, the growth horizon for renewables looks positive.

Pilita Clark, ‘Oil Prices Fall hits UK Biofuel Plan’, Financial Times, 18 February 2015.

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Regional focus – Impacts on the MENA renewable and petrochemical market Written by

Adrian Creed

Partner, Abu Dhabi T: +971 2 494 3501 E: [email protected]

Historically, low oil prices have hurt the renewable energy sector and benefited the petrochemical sector. This is because tariffs for renewable energy become less attractive commercially when assessed against the tariffs for conventional thermal power projects (which tend to fall as feedstock prices decline). Conversely, as feedstock prices fall, the cost of manufacturing petrochemical products declines and profit margins rise. Whilst the fundamental economics behind this equation still apply, there has not been a correlation between this formula and the respective levels of activity in MENA within these two sectors. The MENA petrochemical market is forecast to grow at compound growth of 7.5 per cent this year. Whilst that may sound like a high number, it actually represents a drop in percentage terms. Over the last decade, MENA petrochemical sector growth has been in the double digits rather than single digits. Conversely, the MENA renewables market is growing very quickly, with many MENA countries now looking to significantly ramp up their activities.

MENA petrochemicals market A weak oil price tends to hurt the petrochemical industries of MENA oil producing countries because they lose their comparative pricing advantage over traditional competitors based in Europe and North America that use oil-derived feedstocks such as naptha to make petrochemicals.

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For those petrochemical products that utilise gas rather than oil as their feedstock, most of the major hydrocarbon players in the GCC (with the exception of Qatar) are struggling for gas allocations because of an increasing demand for domestic gas to be used in the utilities sector. Industrialisation and strong population growth within the GCC has given rise to an ever increasing demand for power and water. In the past, countries such as Saudi Arabia tended to exclusively burn oil to power their electricity generation and water desalination projects. This is no longer the case and although Saudi still uses close to a million barrels a day to run its power and water facilities, the policy going forward is that new IPP and IWPP projects are to be developed using gas as the default feedstock.

Energy consumption in MENA is set to double by 2040 and most of the feedstock allocated to meet this growth will be natural gas, making the MENA natural gas market nearly on a par with Europe’s and growing nearly as fast as China’s gas demand. The region has huge gas resources but much of that is in the form of “gas caps” associated with oil reserves and will not be recoverable until the oilfields are depleted. Additionally, most of the recoverable gas reserves are located in Qatar, Iraq and Iran. For geopolitical reasons, tapping into Iran’s gas supply is not part of the plans for the GCC countries, and in Iraq, the fighting and uncertainty mean that offtakers cannot rely upon this market to provide the additional capacity needed. This is a particular concern for countries like the UAE, which face a short-term gas crunch as demand outstrips domestic supply. The end result of this dynamic is that gas allocations are being prioritised for use in the utility sector rather than for use in the petrochemicals sector. The end result for many MENA countries is that for petrochemical projects that use oil as the base feedstock, competitive pricing advantages are being lost because US and European countries now have access to cheap supply, and for those projects that use gas as their feedstock, the petrochemical companies are struggling to compete for allocations against MENA utility companies.

MENA renewables market In our last article, we looked at the impact of the declining oil price on the UK renewables market, concluding that, with the exception of the biofuels market, which we believe will be adversely affected, investment in proven renewables technology is likely to continue largely unaffected by declining oil prices in the short to medium term. In the

MENA region, it would be reasonable to conclude that low oil prices would have a material adverse impact upon proposed new renewable energy projects because conventional thermal power projects are producing cheaper electricity now. In fact, this is not the case. The MENA region is arriving very late to the renewable energy party, but it has serious intent; low oil prices will not derail this initiative. Three high profile deals that have closed in the last few years are the 100MW Shams 1 solar CSP plant in Abu Dhabi, a joint venture between Masdar, Total and Abengoa Solar, which came online in March 2013, the 300MW Tarfaya wind farm in Morocco and the first phase of Dubai’s 1GW Mohammed Bin Rashid Al Maktoum solar park. These projects herald a new wave of major renewable projects, many of which will be in Saudi Arabia. Indeed, Saudi Arabia has announced a colossal program to procure 54GW of new renewable energy capacity by 2032. Meanwhile Morocco and Jordan have outlined plans to install 4,000MW and 1,650MW of renewable energy respectively by 2020, Oman has announced that it is targeting to produce 10% of its energy needs from renewable sources by 2020, and a few months ago Dubai announced that it has tripled its target to increase the share of renewables to 15 per cent of its energy mix by 2030.

Conclusions Our view therefore is that whilst low oil prices have had a significant impact upon the economies of the oil producing nations in the MENA region, there will only be a minimal negative impact upon the region’s petrochemical sector, and virtually no impact upon the region’s push for a future where renewable energy plays a significant role in the energy mix.

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Directors’ liabilities Written by

Michael Wachtel Partner, London

T: +44 20 7876 4216 E: [email protected]

With the current financial difficulties faced by the oil & gas industry, directors of companies incorporated in England and Wales must be mindful of their duties and responsibilities to the company as well as the potential personal liability that could arise from breaching those duties and responsibilities in the context of an insolvency. Who qualifies as a director? Under English law, directors are generally appointed in accordance with the company’s articles of association. In some circumstances however: (i) a person who acts as a director without having been appointed validly, or at all, is subject to many of the same duties and liabilities as a duly appointed director (de facto directors); and (ii) a person who does not act as a director, but in accordance with whose directions or instructions the directors of a company are accustomed to act (shadow directors) can also be fixed with liability. In addition, persons duly appointed by or on behalf of a director to act in his or her place or to stand-in for him or her (alternate directors) are usually deemed to be a director for all purposes and so subject to the same duties and liabilities as any other director.

Directors’ Duties and Responsibilities – Companies in Financial Difficulty Where a company is insolvent, or in danger of becoming so, directors face additional duties and responsibilities, including the requirement to have regard to the interest of the company’s creditors. In these circumstances, directors may need to take difficult decisions and could face personal liability if they take the wrong decisions, it is therefore important to seek professional advice at an early stage.

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Directors may wish to consider the following nonexhaustive list of additional duties and responsibilities: Wrongful Trading Directors of a company in financial difficulty should regularly review with its professional advisers whether it is advisable for the company to continue trading. Many of the agreements commonly used in the oil & gas industry require a company to meet ongoing payment obligations, for example: –– ongoing consideration payments under a farm-in agreement, where the farmee is required to fund a work program over a period of time in order to acquire a participating interest in a production sharing contract (PSC) and related joint operating agreement (JOA); –– cash calls under a JOA, which are required to meet minimum work obligations under a PSC; and –– costs and expenditures required to be incurred under service contracts, for example where such services are required in order to fulfil minimum work obligations, and the corresponding costs and expenditures are recoverable from future production.

Such ongoing payment obligations should be carefully considered by the directors of a company in financial difficulties in order to balance the need for the company to meet such obligations to retain its interest in the relevant asset with its ability to fund those payments. If a company continues to meet its obligations under such agreements and that company subsequently goes into insolvent liquidation, should a court find that a director knew, or ought to have concluded, at some time before the commencement of the winding-up that there was no reasonable prospect that the company would avoid going into insolvent liquidation, then that director may be ordered to make a contribution to the assets of the company. A director can mitigate this risk by showing that he or she took appropriate steps to minimise the potential loss to the company’s creditors. If a company is in financial difficulty and there is any risk of an impending insolvency, board meetings should be held on a regular basis so that the directors can continue to carefully monitor the ongoing situation. A clear and accurate record should be kept of the matters considered, actions taken by directors and external advice received. Any director whose views are not reflected in action taken by the board of directors may wish to ensure that his or her views are clearly and accurately recorded in the board minutes. Fraudulent Trading Once a company goes into insolvent liquidation (that is, where its assets are insufficient to meet its debts and other liabilities, plus the expense of winding up), directors must continue to carefully consider any payments to be made by the company. Directors may be liable if they were knowingly party to carrying on the business of the company with intent to defraud creditors, or for any fraudulent purpose. If directors continue to trade and incur debts at a time when they know there is no reasonable prospect of those debts being paid, either at the time they are due or shortly afterwards, then the requisite intention to defraud may be found. Fraudulent trading is a criminal offence under the Companies Act 2006 and may lead to unlimited civil liability under the Insolvency Act 1986.

Misfeasance If, during a company’s winding-up, it appears that a director or other person involved in the management of a company has misapplied company assets, or been guilty of any misfeasance or breach of duty in relation to the company, the court may order them to restore or account for the assets to the company, or to make a compensatory contribution to the assets of the company. Actions for misfeasance are more common than actions for wrongful or fraudulent trading. Re-use of company names Particular care should be taken where there are directors in common of group companies with similar names and a member of the group goes into insolvent liquidation. As it is usual in many jurisdictions for local subsidiaries to be required to hold oil & gas assets, oil & gas companies are commonly part of complex group structures with multiple subsidiaries sharing a common company name. In certain circumstances, if a company has gone into insolvent liquidation, a person who was a director or shadow director of that company at any time in the preceding 12 months may incur liability if, without the permission of the court, they act as a director or take part in the management of another company with the same or a similar name as the first company. Contravention of the prohibition is a criminal offence and the director may be rendered personally responsible for the debts and other liabilities of the second company. Disqualification A director who contravenes the law risks being disqualified from acting as a director or otherwise being concerned in the management of a company for up to 15 years, in addition to any other liabilities he or she may incur. In addition to breach of the duties and responsibilities noted above, a court must disqualify a director from involvement in the management of any company if he or she is or has been a director of a company which has become insolvent and his or her conduct as a director renders him or her unfit to be concerned with the management of a company.

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Dedicated to the oil & gas industry Our global oil & gas group combine deep practice expertise in their chosen disciplines, sector specialism and regional knowledge. They have a thorough understanding of the industry, its drivers and the issues our clients encounter. The group specialises in all areas of contentious and noncontentious disciplines in oil & gas exploration and production (E&P), upstream and downstream projects and their related infrastructure. It is supported by a wider group of lawyers that have extensive experience in the oil & gas sector across corporate, commercial, finance, projects, disputes and international arbitration. This includes specialised areas such as employment, HSE, regulatory and compliance, insurance, trading and derivatives. We recognise that due to the pioneering nature of the industry, our oil & gas clients are often working in frontier markets, dealing with complex multi-jurisdictional and cross-border transactions and disputes. They require legal advisors who are not only expert lawyers with a deep understanding of the industry but have a commercial approach and pragmatic mindset assisting clients to achieve their goals cost effectively and with a minimum of risk. As part of the Clyde & Co oil price volatility series, we hosted a series of events in London and Aberdeen focusing on the current economic trends in the industry, with an address from the Economics and Commercial Director of Oil & Gas UK, Michael Tholen. Philip Mace, David Leckie and Stewart Perry all took part in a panel discussion looking at some of the legal issues affecting the industry both in the UK and internationally, including wrongful termination, breaches of JOAs and other key contracts, financial distress, insolvency and bankruptcy, cross border insolvency issues and directors’ duties. Should you be interested in any of these topics, please do not hesitate to contact one of the authors or your usual Clyde & Co contact.

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About Clyde & Co Clyde & Co is a leading international firm with over 1,500 lawyers and 2,500 staff operating from 39 offices across six continents. We are fully committed to delivering our combined expertise to further the interests of our clients and to provide an unrivalled service wherever and whenever we are needed. We deliver sector specific expertise across both contentious and transactional disciplines and have a resolute focus on our chosen sectors of energy, trade, infrastructure, marine, aviation and insurance. Across the firm, we have both practice area expertise and the depth of experience in the oil & gas sector worldwide ensuring a familiarity with local nuances so we can assist clients in managing their business operations effectively.

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