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"With declining production, aging infrastructure, and regulation directed at decommissioning, transition and decarbonisation, the North Sea is becoming a bellwether for investors and parties with interests in mature oilfields including so-called 'late life specialists'."
The North Sea was the backdrop for active and diversified market investment in the 1980s, leading to the establishment of Brent Crude Oil as the world’s key price benchmark. Now, with declining production, aging infrastructure and regulation directed at decommissioning, transition and decarbonisation, it is becoming a bellwether for investors and parties with interests in mature oilfields including so-called “late life specialists”. The Brent crude oil benchmark is itself in transition as the industry considers the inclusion of non-North Sea Oil and other changes in the face of liquidity issues and to ensure the benchmark’s continuing relevance.
A favourable regulatory and fiscal environment was one of the advantages of North Sea Oil markets in the 1980s. It seems that the UK government is laying the groundwork for future regulation, at least in the mid/downstream market to assist the industry and ensure supply as the pace of transition quickens. As such, in this edition we consider the draft Downstream Oil Resilience Bill presented to Parliament by the Secretary of State for Business, Energy and Industrial Strategy in June 2021.
In this edition we also review a series of decisions which have been handed down recently in the English courts which focus on reimbursement of advance payments in oil/products sale and purchase agreements and prepayment agreements. We also consider two decisions involving legal principles which are frequently considered in trading disputes.
We next comment on the July 2021 Supreme Court decision of Triple Point Technology, Inc v PTT Public Company Ltd¹ (in which our Energy Sector disputes team acted for the successful party). That judgment focussed on important questions concerning the law of liquidated damages in relation to an agreement for the development and installation of a commodities trading risk management platform.
With respect to LNG, we look at some of the more significant issues faced generally by LNG vessel owners when constructing and financing LNGCs against long-term charters. Furthermore, we report on natural gas and where this currently fits in EU Taxonomy.
Finally, our Energy Sector team has recently been enhanced by two partners joining WFW and we extend a warm welcome to Julian Nichol and Sumeet Malhotra.
Contents
- Mature oilfields and aging infrastructure
- Platts’ July 2021 consultation on the inclusion of WTI in the Brent complex
- Downstream Oil Resilience Bill
- Prepayment, advance payment and the uncertainty of supply
- 2021 focus on trading
- Triple Point Technology, Inc v PTT Public Company Ltd
- LNGCs for new LNG export projects
- Gas taxonomy
- Expanding our global expertise
Mature Oilfields and Aging Infrastructure
In late 2020, we saw the recovery of oil prices from the low levels experienced during the initial lockdowns of the Covid-19 pandemic and a corresponding resurgence in new M&A activity this year. What about existing projects involving mature oil fields? Although such price increases also improve the economics for mature oil fields, capital expenditure has still not returned to levels seen in the better years prior to the pandemic. Challenges will continue to arise, for example, if there are major seaworthiness/class issues affecting offshore Contractor units and/or other significant oil field production issues facing the Operator.
In long term Service Agreements, many Contractors and Operators will be familiar with the tension between a Contractor’s duty to maintain and repair equipment (in some cases coming towards the end of its economic life) and the Operator’s duty to keep marginal oilfields in production, albeit sometimes with a relatively short or uncertain future. On the other hand, both Operators and Contractors also have the additional jeopardy of complying with local decommissioning or international recycling regulations if the oil field cannot be kept in operation or new employment is not found for the unit. Older units can experience major damage requiring off site repair, leading to the shut-down of the oil field if a substitute unit cannot be found. Service Agreements are often drafted without sufficient focus on the scenarios which may arise as they approach termination. Where the issues are capable of identification, due diligence should be conducted well in advance of any potential expiration periods. Time may be needed to involve technical or market experts, obtain detailed legal advice and potentially, to resolve issues with the counterparty through negotiation, arbitration, mediation or other forms of ADR.
"Does the Good Oilfield Practice standard in Production Sharing Agreements… give rise to certain obligations when considering the economic life of an oil field?"
One issue that might arise is the role of the Good Oilfield Practice standard in Production Sharing Agreements. Does this obligation give rise to certain obligations when considering the economic life of an oil field? Or maintaining/repairing equipment? Does the standard just encompass safety and operational matters, or does it extend to closely related economic questions and what should feature in work plans and budgets for coming years?
Aside from particular Operators’ and Contractors’ duties, major oil field infrastructure such as pipelines used in common by all producers in a field can be in the hands of owners needing life extension strategies. These parties are likely to be reviewing their contracts in detail to see what rights they have to increase tariffs and whether contractual discretions or flexibility can be used in order to save costs or increase revenue. Disputes can arise as the limits are tested. We saw this in the 2020 case of Apache North Sea Ltd v INEOS FPS Ltd². The Forties Pipeline System (FPS) is owned by INEOS FPS Limited (acquired from BP in 2017). Apache (which produces approximately 60,000 barrels per day from its Forties field licences) sought to update an appendix to the transportation and processing agreement with INEOS to include its estimated production profile for years 2021–2040. Under the terms of the transportation and processing agreement this right was subject to INEOS’ consent, not to be unreasonably withheld. INEOS refused consent to the amendment on the grounds that Apache did not agree to pay an increased tariff of £1.20 per barrel (up from £0.60). The Commercial Court found that INEOS could not make consent subject to such a condition. Read more here.
The INEOS case is an example of an impermissible use of one type of contractual discretion. However, agreements, particularly those containing clauses referring to “sole and absolute discretion” for one party, will give the decision maker more scope. Parties benefiting from such discretions argue that they mean what they say and the party resisting the exercise of such discretion are often left relying on arguments that the discretion does not allow the counterparty to make a decision which is capricious, arbitrary and irrational. These grounds are high hurdles to satisfy.
As many upstream agreements are long term arrangements, a party may argue that the nature of the agreement is “relational” and therefore certain terms requiring good faith should be implied, limiting the scope for a decision maker. In some relatively recent cases, the English courts have had to consider attempts to imply such terms into agreements where rights do not appear to have been qualified at all. Parties arguing in favour of implying requirements of good faith often cite the principle in the Supreme Court decision of Braganza v BP Shipping Limited³, where the court implied such terms in favour of a former employee’s widow seeking death benefits. However, generally, with respect to Oil & Gas agreements which are detailed negotiated agreements between experienced parties, the courts will focus on the language used and adopt more of a “mean what they say” approach.
"As many upstream Oil & Gas agreements are long term arrangements, a party may argue that the nature of the agreement is 'relational' and therefore certain terms requiring good faith should be implied, limiting the scope for a decision maker."
In a wider context, changes to legislation in order to advance policies such as transition or decarbonisation may alter expectations and create contractual disputes between contracting parties, shareholders or even disputes between investors and host states under investment treaties. When it comes to the environment, there is also potential for regulatory claims by governments against corporations in the Oil & Gas sector and even claims by private parties claiming to be affected or with political agendas. The potential for decarbonisation and other environmental policies to cause disputes in the future was a major theme this spring during London International Disputes Week.
Finance facilities, whereby lenders have periodic options or discretion to review security or to renew or extend the facilities altogether, are coming under increasing scrutiny by borrowers and lenders. Significant new policies affecting regulation and legal developments in the sector may result in lenders having less appetite for high carbon industries. If there is a wide enough option or contractual discretion, it may only take one lender in a syndicate to decide that it is no longer interested in lending into the Oil & Gas sector in order to significantly increase the cost of financing, or place other restrictions on the borrowers that were not thought likely when the original facility was entered into.
Decommissioning risk under the Petroleum Act 1998 was brought into focus in the High Court’s decision in Apache UK Investment Limited v Esso Exploration and Production UK Limited⁴ in May 2021. The case concerned a dispute between the Buyer and Seller of licence interests in 2011 in a number of fields in the North Sea. Specifically, the case related to obligations of the Buyer to secure the Seller against the risk of future decommissioning liability. The decision of the court meant that Apache had to first provide significant decommissioning security in favour of Esso, calculated by reference to the criteria in the 2011 sale notwithstanding that a decommissioning plan prepared after the triggering event in 2020 indicated that the security could have been about US$130m less. On the other hand, Apache did not have to provide security to Esso in respect of several wells which had not been developed at the time of the 2011 sale. Although this second part of the decision is ultimately one for the regulator, the court did not accept that Esso’s exposure to decommissioning obligations (having sold in 2011) could be so wide as to extend to wells which at that time (and on the evidence before the court) were not intended to be developed.
The bilateral Decommissioning Security Agreement (DSA), in this case entered into with respect to the sale where there was no pre-existing decommissioning plan, was a bespoke document. The decision has limited application to the Standard form field-wide Model DSAs which are entered into between operators and (current and often former) co-licensees to protect their respective interests. Nevertheless, the court’s decision highlights the relationship between Decommissioning Plans, DSAs and the scope of the Secretary of State’s powers under the Petroleum Act 1998, including issuing section 29 notices. Reported decommissioning disputes are rare but this decision may be a sign of things to come. Read more here.
For more detailed commentary on decommissioning agreements, refer to Chapters 5 and 6 of Pereira et al, The Regulation of Decommissioning, Abandonment and Reuse Initiatives in the Oil and Gas Industry from Obligation to Opportunities, (Wolters Kluwer 2020). Chapters 5 and 6 were authored by WFW Corporate Partner Heike Trischmann.
Platts’ July 2021 Consultation on the Inclusion of WTI in the Brent Complex
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"Recent market controversy over Platts’ decision to incorporate West Texas Intermediate Midlands into its basket of crude oils used to determine Brent crude oil prices is another sign of the times for North Sea crude oil."
The recent market controversy over Platts’ decision to incorporate West Texas Intermediate (“WTI”) Midlands into its basket of crude oils used to determine Brent crude oil prices is another sign of the times for North Sea crude oil. One of the initial strengths of the Brent crude oil market was that there was a sizeable production of relatively homogeneous sweet crude oil from one relatively small region originally available from a single terminal with regular sea-borne delivery schedules. This made Brent crude oil highly tradeable, leading to it becoming the world’s leading crude oil benchmark.
As production in the North Sea has declined, one of the weaknesses in the Brent market is now liquidity. With production in the original oil fields having slowed or ceased, crude from newer oil fields is added to the basket of crude oils making up Brent prices. We now have a collection of crude oils from the Brent/Ninian, Forties, Oseberg, Ekofisk and Troll fields (BFOET) in the North Sea. In order to account for market adjustments for differing crude oil quality, Platts has added a sulphur “de-escalator” to certain crude oils, such as Forties, which is an adjustment to the price based on sulphur content. Commentators further suggested that future candidates for inclusion in the Brent basket would (for the first time) come from crude oils produced in different global regions. In February and March 2021, Platts first announced and then deferred, pending further consultation, the introduction of changes to its Dated Brent benchmark which would have included WTI Midland and a shift to a CIF based benchmark by 2022. Platts has now followed up with a consultation White Paper in July 2021 calling for submissions from stakeholders by end of September on the inclusion of WTI.
The White Paper “aims to lay out the reasons why the Brent complex needs to continue to evolve in order to retain its role as the world’s leading crude oil benchmark ecosystem”. Together with the ICE, Platts solicits feedback through a common set of questions on the evolution of the Brent complex. The White Paper focusses on both the case for new oil streams, with adjustments to be made for quality, and oil streams which are from different regions with different logistical characteristics. In relation to the latter, Platts has already begun including delivered (CIF) cargo prices to the Brent complex in addition to the traditional FOB cargos. It points out, however, that this is more complicated when adding crude oil streams from outside the North Sea. When proposing WTI in December 2020 Platts proposed a virtual FOB WTI Midland loading programme at Scapa Flow in the Orkneys where oil transhipments have taken place for some years/decades. This didn’t go down too well with the market, but Platts is now confident that with the input already received “the lack of a loading program in the US Gulf Coast no longer appears to be insurmountable”.
The issues in the White Paper are identified and questions asked about (i) the inclusion of oil from the Johan Sverdrup field as a deliverable option under the Forward Brent Contract, which would remain on an FOB basis, and for bids and offers for this grade to be factored into the Dated Brent Assessments; (ii) including WTI Midland as a deliverable grade on an FOB USGC (to be more closely defined) basis; and (iii) increasing parcel size in the Brent complex from 600,000 to 700,000 barrels (in order to align the typical minimum parcel size for WTI and with the larger Aframax-sized vessels which have become more prominent of late). You can read the White Paper here and one of our previous articles on Brent here.
Downstream Oil Resilience Bill
"The Downstream Oil Resilience Bill diverts from the longstanding approach that the midstream and downstream oil market does not need to be regulated."
The Bill diverts from the longstanding approach that the midstream and downstream oil market does not need to be regulated. However, rather than liberalising the oil market (as we have seen with electricity and gas market regulation), the Bill is designed to protect the mid/downstream oil market in the vein of an increasing number of companies embracing transition and selling or at least reducing their exposure to oil-related businesses, thereby causing a reduction in domestic oil product supply sources. The Bill gives the Secretary of State for BEIS powers to give directions to act or refrain from acting, require certain market information but also to restrict the sale of qualifying assets in line with the recently adopted National Security and Investment Act 2021. However, it is perhaps the ability of the Government to hand out financial support to the (future/potentially) ailing mid/downstream oil industry that is the most controversial. Whilst no doubt welcome by the industry, it potentially strikes a discordant note ahead of COP26. It also may not sit well with environmentalists already actively alleging that taxpayers’ money is being used to subsidise fossil fuels in other areas. Read more here.
Prepayment, Advance Payment and the Uncertainty of Supply
Between March 2020 and May 2021, there have been several reported industry related decisions where the English courts considered whether sellers were in breach for failing to deliver crude oil or oil products under agreements for sale which had provisions for advance payments or were part of a prepayment arrangement. In each of these cases the sellers were unsuccessful in persuading the court that buyers were not entitled to reimbursement. Defences included sellers re-characterising deals in order to interpret relevant rights and obligations and making claims of force majeure in order to overcome general reimbursement obligations.
Perhaps a straightforward example of a prepayment claim was seen in the June 2020 decision of Trafigura PTE Limited v Government of the Republic of South Sudan and the Bank of South Sudan⁵, where Trafigura obtained summary judgment after an absence of any acknowledgement of service. The Commercial Court was satisfied that there was no prospect of the Government successfully defending the case after reviewing the SPA and PPA, checking service, waiver of state immunity and the applicability of the guarantee to the outstanding amounts.
A claim in respect of advance payments in sale and purchase transactions was seen in the case of BP Oil International v Vega Petroleum Ltd⁶ in June 2021. In this case, the defendants had entitlements from the state-owned Egyptian General Petroleum Company (“EGPC”) under a JV agreement concerning oil from the Ras El Ush Field in the Gebel El Zeit Concession in Egypt. The defendants effectively sold all their entitlements to BP, receiving advance payments for a series of FOB contracts. As a matter of course in Egypt, approval from EGPC was required before any oil could be lifted. Although oil was successfully lifted in 2012-2015, for deliveries in 2016 approval had not been granted by EGPC and the defendants had failed to deliver about 200,000 bbls for which they had received US$17m. BP eventually terminated the agreements.
Although the parties discussed settlement by way of assignment of Vega’s rights against EGPC, BP eventually sued for the return of the sums prepaid by way of unjust enrichment claims on the basis that it had received no consideration under the purchase contracts. Vega argued that, under the purchase contracts, both parties understood that the payments were unconditional and BP had no recourse to recover them. It was further argued that BP had received consideration in the form of its entitlement to lift oil and that such rights were tradeable. The Commercial Court found that on their face the sale agreements were contracts for delivery FOB, which had an understood meaning in the industry. There was no reference to any delivery requirements being dependant on Vega’s joint venture or factual matrix which suggested this. Accordingly, BP was entitled to be repaid owing to the non-delivery. Furthermore, BP’s claim for unjust enrichment and right to repayment was reflected in the provisions of section 54 of the Sale of Goods Act 1979. Read more here.
In March and November 2020, two summary judgment decisions were reported concerning oil products sale and purchase agreement disputes between the Zug-based New Stream Trading Group AG (NST) as sellers and Totsa Total Oil Trading SA and Nord Naptha Limited respectively as buyers⁷. Although these are 2020 cases, there are other reported decisions in relation to parties caught in the fallout over the collapse of the Antipinsky oil refinery and some claims are ongoing. The background to this collapse seems to be complicated and may involve actions against parties outside of the normal contractual chains.
The Total and Nord Naptha disputes involved similar non-delivery on the part of NST following 90% advance payments, defences of force majeure and terminations after a 30 day contractual period for continuation of force majeure.
The Total case was a summary judgment application where the claimant had to accept, for the sake of argument, that there was a force majeure event. However, the court had no difficulty in finding that a clause which promised reimbursement to the buyer of any advance payment where deliveries were not made included a scenario where a force majeure event had existed for 30 days and the contract had been terminated thereafter. These findings were largely confirmed in the November 2020 Nord Naptha decision with the court going further by saying that even if the clause regarding reimbursement did not expressly confirm its enforceability notwithstanding force majeure claims, this would be implied.
Both Vega and NST received substantial prepayments or advance payments where it appears that their ability to supply was dependent on entities of significant substance and power in the jurisdiction in which the oil or product was sourced. Both Vega and NST referred to having substantial claims against their suppliers whose failure to deliver was the reason for the non-delivery to their customers.
Vega’s claims are referred to in the court’s judgment but were apparently not considered by BP as assets of sufficient value on which to base a settlement. We are not aware whether Vega was able to satisfy the judgment and/or whether BP had alternatives for enforcement.
NST’s claims against its supplier and others are described on its website. In a press release dated September 2019, NST said it had claims against the Antipinsky Oil Refinery as well as Sberbank of Russia, Sberbank (Switzerland) and related parties in an LCIA London arbitration. We have no reports on whether enforcement of the judgments obtained by NST’s buyers have been successful.
"Counterparty risks in advance payment or prepayment agreements… can sometimes be mitigated by security and/or insurance. Absent these, judgments or awards confirming reimbursement or restitution may turn out to be merely the point at which such counterparty risks materialise."
In conclusion, the English courts will not easily re-characterise sale agreements for the delivery of oil or products and will not readily accept as a matter of construction, even with force majeure allegations, that advance payments are not intended to be ultimately reimbursable where there is a failure to deliver. Furthermore, particularly for one-off sales, there may be a remedy in restitution as envisaged by section 54 of the Sale of Goods Act 1979. However, counterparty risk in advance payment or prepayment agreements can often be significant. These risks can sometimes be mitigated by security and/or insurance. Absent these, judgments or awards confirming reimbursement or restitution may turn out to be merely the point at which such counterparty risks materialise.
2021 Focus on Trading
In May and June 2021, the English High Court and Court of Appeal handed down decisions on issues which often have to be considered when interpreting trading contracts and also, in the case of Galtrade Limited v BP Oil International Limited⁸, assessing damages for breach.
Trading contracts often take the form of a recap or “Part 1”, containing essentials of the deal and incorporating detailed standard or general terms and conditions. These terms are often those of an oil major such as BP or Shell and are publicly available. The agreements often contain a provision stating which terms take priority in case of a conflict, but what counts as a conflict? Although similar principles have been applied many times in relation to different types of trading contracts, it is useful to see the courts apply such terms in relation to a contract for the sale of oil products.
In Septo Trading Inc v Tintrade Limited⁹, the Court of Appeal considered whether a certificate of quality issued by an independent inspector was binding on all parties in relation to quality issues. The recap said the result of the certificate of quality was binding on all parties save for fraud or manifest error, but the standard printed terms (in this case the BP 2007 General Terms and Conditions, “GTCs”) stated that they only applied for invoicing purposes. However, the GTCs also expressly stated that they only applied “where not in conflict” with the recap. The Court of Appeal held that the clauses in the GTCs were in conflict with the recap and therefore formed no part of the agreement. Read more here.
The case of Galtrade involved a sale and purchase dispute arising over the quality of straight-run fuel oil (SRFO) mainly used as a refinery feedstock. Does an FOB buyer have a right to reject an off-spec cargo based on the seller’s breach of the contractual specification for the goods in question?
"After a five-day hearing and a 62-page judgment in which the court appears to have analysed all of the arguments, including the damages cases presented by both parties, the court decided that the buyer and seller were each entitled to judgment for nominal damages."
The parties in Galtrade agreed that the cargo was off-spec in relation to sulphur content and other aspects, although the extent to which these aspects affected marketability of the cargo was disputed leading to the court allowing expert evidence both as to physical quality of the product and the consequences for oil trading/marketability. The court held that the buyer did not have a right to reject. It is noteworthy in this case that even though the rejection was wrongful giving rise to damages, the seller still had to account for its breach in supplying an off spec cargo and its mitigation efforts in re-selling the rejected cargo were effective. After a five-day hearing and a 62-page judgment in which all of the damages arguments were analysed, the court decided that the buyer and seller were each entitled to judgment for nominal damages.
Despite its length, the decision is worth reading. Firstly, it illustrates the difficulties in traders arguing that a seller’s breach in supplying off-spec products, absent clear language in the contract, is a breach of condition entitling the buyer to reject the goods. The fact that the parties are traders also sets a high bar for arguments that the delivery of off-spec products amounts to a repudiatory breach which renders the product something completely different from what was bargained for (thereby entitling the buyer to reject). This was particularly the case in this instance where the product was intended to be used in a secondary refining process and could itself be blended with other products to produce the desired specification for on-sale to refineries. Secondly, the decision illustrates that even after findings on the issue of breach, the outcome of a hard-fought hearing on quantum issues for calculating damages can be difficult to predict. Read more here.
Triple Point Technology, Inc v PTT Public Company Ltd
For some years now, there has been a major focus in the Oil & Gas, as well as other commodities industries, on how to digitise trade. Some companies have spent millions trying to develop trading platforms in order to make trading more standardised, efficient and secure. But what happens when your software developer fails to deliver, breaches its core duty to use reasonable care and skill and, following delays, you then decide to call time on the project before it is completed? Even after a breach of the developer’s core duty is established, damages can still be a major stumbling block as you must navigate limitation of liability clauses, liquidated damages provisions and caps on liability.
"Given the purpose of a proposed commodities trading software system, carefully drafted liquidated damages and limitation of liability provisions were vital to give the parties certainty and protect the software developer from uncapped damages at large for breaches of contract."
The Supreme Court in Triple Point Technology, Inc v PTT Public Company Ltd, a case in which WFW acted for the successful appellant, concerned a failed project for the design and implementation of a new business software system that was to be used by a state-owned oil company for commodities trading, charterparty management and hedging trading risks. Given the purpose of the system, carefully drafted liquidated damages and limitation of liability provisions were vital to give the parties certainty and protect the software developer from uncapped damages at large for breaches of contract. Once the issue of breach had been established, questions as to the applicability of the liquidated damages provisions and as to the scope of the limitations of liability therefore came into central focus and were the subject of two appeals.
As explained more fully here, the recent Supreme Court judgment has provided welcome clarity to the applicability of the “orthodox approach” to the interpretation of liquidated damages provisions when a contract is terminated prior to completion. The court’s decision on the central question of limitation of liability (overruling both the court at first instance and the Court of Appeal), is of significance too, having found that the use of the word “negligence” in a carve-out to the limitation clause was found to cover equivalent contractual breaches as well as just free-standing torts. The case has received a great deal of coverage, particularly in the construction sector. However, it is also a useful reminder of key points to consider in the allocation of risk/liability in the ongoing push to further digitise and streamline trade.
LNGCs for new LNG Export Projects
2020 was a challenging year for the developers of LNG export projects. It is now hoped that a number of the postponed projects will soon reach final investment decision, leading to a commensurate demand for newbuild LNG carriers. This is good news for shipowners. However, independent export projects give rise to additional challenges and in the latest issue of Marine Money, Partners Joe McGladdery and Simon Kavanagh look at some of the more significant issues faced generally by Owners when constructing and financing LNGCs against long-term charters, focussing in particular on the challenges arising from such projects. You can read their article here.
Gas Taxonomy
A ‘green’ label has become a very important parameter in today’s energy industry, particularly in Europe. The EU’s green finance rules are intended to ensure investment is channelled into environmentally friendly, sustainable projects and away from fossil fuels. This will be achieved, in part, by encouraging finance providers to disclose from the end of 2021 which investments meet climate criteria as provided in the various performance thresholds for certain economic activities which we have looked at before in respect to various sectors. Read more about EU taxonomy with regards to transport, energy and mining minerals and metals.
The EU’s taxonomy system is being developed through Regulation (EU) 2020/852 and delegated acts published in two parts. The delegated act on the first two climate-related objectives (i.e. “Climate Change Mitigation” and “Climate Change Adaptation”) should have been adopted by the Commission by 31 December 2020 for it to start applying as of 1 January 2022 but was delayed to 21 April 2021 with a solution on natural gas still outstanding.
The political agreement that was reached in December 2019 expressly excluded power generation activities based on solid fossil fuels from being eligible under the EU taxonomy rules but was altogether silent on natural gas. Instead, natural gas was supposed to be subject to a technical assessment for the development of the delegated legislation. And there is much at stake: if not considered ‘sustainable’ and a ‘transition fuel’ or at least as doing no significant harm, gas-fired power generation would not be able to attract the funding necessary to drive the transition from coal-based to carbon neutral power generation.
Draft rules published by the European Commission on 20 November 2020 as part of a public consultation set out that electricity production from gaseous and liquid fuels is considered a “transitional activity” only as long as it does not emit more than 100 grams of CO2 equivalent per kilowatt hour, a level experts agree cannot be met with current technologies which cause emissions to be nearer 300-350g and would cause natural gas technologies to miss out on required financing. Even to qualify as causing no significant harm, the level of emissions must not exceed 270gCO2e/kWh. Although this may be opening the door for natural gas to be labelled as a “transitional activity”, it would require it to be blended with low-carbon gases at a rate of approximately 30%.
The public consultation closed on 18 December 2020, with significant push back from 10 eastern and southern European countries (Bulgaria, Croatia, Cyprus, Czech Republic, Greece, Hungary, Malta, Poland, Romania and Slovakia) which still rely to a large extent on coal for their power generation and emphasised the need to maintain the possibility of using natural gas as a transition fuel to be able to achieve their decarbonisation targets. As a result, the final provisions, which were initially due to be published by 1 January 2021, were delayed to 21 April 2021 but with the resulting Delegated Act still not bringing any resolution on the subject matter. Europe is now keenly awaiting a “complementary Delegated Act” that “will be adopted later in 2021” as promised by the Commission back in April. The stalemate reflects the difficult balancing act the Commission has to undertake between pushing forward its green agenda in a meaningful way and not leaving a large part of its member states alienated.
Expanding our global expertise
We are delighted to announce that the following partners have recently joined WFW. In London, we welcome Partner Julian Nichol to the firm’s Projects Group. Julian brings with him more than 25 years of projects experience, especially in the emerging markets of sub-Saharan and North Africa, the Middle East and Latin America, where he primarily assists sponsor-side clients on the development, financing, acquisition and disposal of power, upstream oil and gas, waste-to-energy and infrastructure projects.
In Singapore, we welcome Partner Sumeet Malhotra, a commodities disputes specialist, to our ranks. Sumeet, brings with him a wealth of expertise, particularly in advising commodity traders on trade disputes, structured trade finance, trade credit insurance and shipping/charterparty matters. This experience has been gained on both sides of the table as prior to working in private practice, Sumeet spent more than 13 years in-house at leading commodity trading houses and ship-owners/ship-managers, including Cargill, Noble Group and Bernhard Schulte.
Our Energy Sector team looks forward to working with Julian and Sumeet as we continue to expand our offering to our growing client base in this sector.
[1] [2021] UKSC 29
[2] [2020] EWHC 2081 (Comm)
[3] [2015] UKSC 17
[4] [2021] EWHC 1283 (Comm)
[5] [2020] EWHC 2044 (Comm)
[6] [2021] EWHC 1364 (Comm)
[7] Nord Naphtha Ltd v New Stream Trading AG [2020] 11 WLUK 281 and Totsa Total Oil Trading SA v New Stream Trading AG [2020] EWHC 855 (Comm)
[8] [2021] EWHC 1796 (Comm)
[9] [2021] EWCA Civ 718
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