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COVID-19 and force majeure positions on Oil & Gas industry standard agreements

The consequences of the COVID-19 outbreak for the energy sector have been wide reaching, with issues such as workers self-isolating, rig closures and disrupted supply chains. Several oil and gas companies have become increasingly concerned that this will result in an inability to fulfil their contractual obligations, causing a surge of enquires related to invoking the “force majeure” provision of contracts. As force majeure is a contractual concept under English law (though not under certain civil law regimes), each case has to be regarded on its own individual merits.

In practice, force majeure clauses may have a variety of forms, some of which are further detailed below, but the overarching principle is that an unprecedented event has occurred, which prevents a party from actually performing its contractual obligations (rather than it is more expensive to do so) and typically that force majeure event is the sole cause of the party’s inability to perform. This may clearly be more of an issue where performance is also influenced by the recent crash in the oil price (which would not qualify as force majeure). In addition, the party relying on force majeure would usually have to take steps to mitigate the effects of a force majeure event – the spread of COVID-19, or government announcements regarding the risks, do not in themselves constitute force majeure.

Current events are particularly notable when contrasted against the Ebola outbreak of 2014 where the government controls were similar (and potentially qualified as a change in law causing force majeure) but the impact was much more localised, allowing greater opportunities for international companies in particular to withdraw employees or otherwise mitigate the effects of force majeure.

Force majeure is distinguished from the English common law doctrine of frustration, which requires a more stringent standard of proof to be met, with the requirement being it has become impossible to perform the contract, rather than merely more difficult. For this reason, it is often more feasible to invoke a force majeure provision, provided that the contract allows for it.

There are four considerations to be made when attempting to rely upon a force majeure clause:

  • Are there specific references to “epidemic,” “pandemic,” “acts of God” or “acts of government” in the definition of force majeure event?
  • What are the conditions that must be met in order to invoke the clause?
  • What would the contractual consequences be if the clause were to be invoked? This could include termination of contract, suspension of particular contractual obligations (e.g. take-or-pay liabilities), extensions of time or allocation of losses.
  • Is there any interaction with mandatory local law? It is vital to ensure that enforcing any force majeure provisions would not contravene any legislation in the jurisdiction in which the contract is based.

The table below sets out some of the different applications of force majeure in oil and gas industry standard contracts, varying from the “exhaustive list” approach of LOGIC contracts, to the somewhat more restrictive approach of the AIPN JOA, which covers only “lockouts, and other industrial disturbances.”

Force majeure and COVID-19 in various oil and gas industry standard agreements

Agreement Summary of FM provision Application to COVID-19 and analysis
AIPN JOA
(Article 16)

AIPN UUOA
(Article 18)

The definition of force majeure in the AIPN JOA and UUOA generally mirrors the associated upstream petroleum contract. The affected party should consider force majeure in line with such agreement. One of the specific events listed in the optional provision of the AIPN model contract is “lockouts, and other industrial disturbances even if they were not beyond the reasonable control of the Party.” It is arguable on the commonly received meaning of the term that a lockout can only apply in the context of a labour dispute, though an industrial disturbance would likely be of wider application and may be more useful. 
South Eastern Africa upstream licence
  • Any failure to comply, or delay in complying, with any non-payment obligation (in whole or partially) set out in the [licence] by either Party will be justified and to the extent that such failure/delay has been caused by force majeure.
  • Force majeure means any cause or event beyond the reasonable control of the affected Party, which is the cause of the default or delay in compliance. Force majeure events include epidemics, blockages, public order disturbance, labour disturbance, quarantines and government illegal acts.
One of the specific events listed in the [licence] force majeure clauses is an “epidemic.” COVID-19 has been classified by the World Health Organisation as a pandemic, a further level of materiality, though depending on the circumstances it may be that its local effects (and, most importantly, its effect on the claiming Party) are less severe.

Other events that may be applicable are “quarantines” or “public order disturbance” i.e. the Concessionaire is unable to carry out minimum work obligations due to the lack of manpower caused by a quarantine order issued by the host government.

Northern Africa upstream licence
  • Any event delaying or preventing the performance by a Party of its non-financial obligations under the PSC is considered as force majeure provided that the occurrence of such event or circumstances is:
    • irresistible;
    • unforeseeable; and
    • independent of the will of the party invoking force majeure.

    In exceptional circumstances an extraordinary or supernatural event, foreseeable but irresistible and independent of the will of the invoking Party, may also constitute force majeure. 

Whilst the PSA does not contain a list of specified force majeure events, it is drafted very broadly and states that any event causing the delay/preventing the performance of the affected party can be considered as force majeure, provided that such event is irresistible, unforeseeable and independent of the will of the party invoking force majeure.
Energy Charter Treaty Force majeure means “irresistible compulsion or coercion, unforeseeable course of events, fulfilment of contract.” In the absence of the express inclusion of relevant events such as “epidemics,” “acts of government” or “quarantines” as force majeure events, it is challenging to establish that the non-fulfilment of contractual obligations is impossible.
It may be worth reviewing other applicable provisions in the ECT, such as the stabilisation clause or hardship clause (if applicable). For instance, where a hardship clause is provided, the affected party may be entitled to call for renegotiation of the contract, if the continued performance of the affected party’s obligation has become excessively onerous due to the outbreak of COVID-19.
LOGIC Contract (Clause 12)
Leading Oil & Gas Industry Competitiveness
  • Neither Party is responsible for any failure to fulfil its contractual obligation to the extent that fulfilment has been delayed or temporarily prevented by a force majeure occurrence, which is beyond the control and without the fault or negligence of the affected Party exercising reasonable diligence.
  • Force majeure includes the occurrence of the following: “other natural physical disaster (excluding weather conditions)” and “changes to any general or local Statute, Ordinance, Decree, or other Law, or any regulation or bye-law of any local or other duly constituted authority or the introduction of any such Statute, Ordinance, Decree, Law, regulation or bye-law.”
While the force majeure definition is an exhaustive one, as social distancing is now statutory in a number of countries, to the extent that companies are required to close their operations this may qualify as a change in law.
Beach UK gas sales terms 2015 (Clause 9)
  • Force majeure means any event/circumstance or combination of both beyond the reasonable control of the affected Party (acting or having acted as a Reasonable and Prudent Operator) which results in or causes the failure (including by delay) or inability by the affected Party to perform its contractual obligations, and such failure/inability could not have been overcome by exercising the standard of a Reasonable and Prudent operator.
  • Force majeure includes:
    • in the case of the Seller, the loss, physical inoperability or failure of the Seller’s Facilities but only to the extent that such loss or physical failure has been caused by an event or circumstance beyond the reasonable control of the operator of the Seller’s Facilities acting and having acted as a Reasonable and Prudent Operator which has resulted in the Seller being unable to satisfy its obligations to supply Natural Gas to any Person; and
    • in the case of the Buyer, the loss, physical inoperability or failure of the National Transmission System and any inability of the National Transmission System to receive at the Delivery Point or transport Natural Gas from the Delivery Point.
  • Force majeure does not include:
    • any failure by the Party to the extent that such failure is attributable to the affected Party’s inability to make a profit or achieve a satisfactory rate of return; or
    • the failure by the Seller to tender for delivery Natural Gas to the Buyer as a result of the inability or geophysical failure of any reservoir to produce Natural Gas or the failure of performance, depletion or exhaustion of any reservoir.
The British government has issued new rules on “social distancing” to address the outbreak of COVID-19. Whilst one of the four reasons that one can leave home is travelling to and from work, this is only permitted where such work cannot be done from home. One potential consequence of these restrictions is a lack of manpower at a Seller’s Facilities, though it is questionable whether, as a Reasonable and Prudent Operator, the Seller would order the complete shutdown of its Facilities.

For the Buyer to invoke force majeure relief, the Buyer must establish that the force majeure event (i.e. failure to transport Natural Gas from the Delivery Point) is caused by the outbreak of COVID-19, not due to the reduced downstream demand or lower market price. The Buyer is also required to show that there are no alternative means for performing its obligations and it has taken reasonable steps to mitigate or avoid the effects of the force majeure event i.e. whether the Buyer has taken steps to solve the transportation issue.  

Next steps

Given the widespread effects of COVID-19, it is important to clarify whether force majeure is applicable in your contracts and to consider an appropriate legal strategy early. Incorrectly invoking force majeure may itself amount to a repudiatory breach and there might be better contractual ways to deal with the current disruption to your operations. If you are currently negotiating a new contract, or conducting due diligence, you should review carefully any proposed force majeure clause and other contractual terms to consider if risks in respect of COVID-19 are appropriately addressed.

If you have any concerns in relation to your oil and gas contracts or require specific assistance with any of the points noted above, please contact a member of the Dentons Energy team.

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COVID-19 and force majeure positions on Oil & Gas industry standard agreements

Natural Gas Public Company of Cyprus (DEFA) issues request for proposals for €500m LNG import facility

Cyprus’ long standing plans to import gas to the island have taken a big step forward with the release on 5 October 2018 of a request for proposals to design, construct, procure, commission, operate and maintain an LNG import facility at Vasilikos Bay, Cyprus (the Project).

It is interesting to note that (unlike previous tenders for LNG imports to Cyprus) the infrastructure is being tendered for separately to the LNG supply. DEFA expects to issue a request for expressions of interest for LNG supply to the market later this year, with a full RfP to follow in early 2019.

Overview of Project

The RfP divides the Project into three distinct elements:

  • The engineering, procurement and construction of the offshore and onshore infrastructure, including the gas transmission pipeline and associated facilities;
  • The procurement and commissioning of a floating storage and regasification unit (FSRU), through the purchase of an existing FSRU, design and construction of a new-build FSRU, or conversion of an LNG Carrier and, if applicable, provision of a floating storage unit (FSU); and
  • The Operations and Maintenance (O&M) of the infrastructure and FSRU for a period of 20 years.”

The following points are worth drawing out:

  1. the Project must be completed by 30 November 2020;
  2. initially, all gas imported through the facility will be sold on by DEFA to the Electricity Authority of Cyprus (EAC, the state owned electricity company, which owns and operates the Vasilikos power station adjacent to the proposed site of the facility). The Vasilikos plant is currently running on heavy fuel oil, but will burn gas once the Project is complete.
  3. DEFA has incorporated a special purpose vehicle, Natural Gas Infrastructure Company of Cyprus, for the Project. The SPV will contract with the successful bidder for the construction and O&M services; and will own the LNG import facility once constructed;
  4. DEFA will contract directly with suppliers for the LNG supply; and will acquire capacity in the facility from the SPV. The risk allocation between the various agreements that will need to be entered into between DEFA, the SPV, the LNG supplier and EAC will be a critical issue for the success of the project.
  5. DEFA will have an option to take over certain elements of the offshore and onshore O&M services at different stages of the Project;
  6. as part of the onshore infrastructure, the contractor will be required to install a “natural gas buffer solution”. The design of this piece of infrastructure is left for the contractor to propose, but could for example include a pipeline array. The intention behind this requirement is to ensure that the FSRU and pipeline infrastructure is capable of achieving the flexibility of gas supply required to meet the operational requirements of the Vasilikos plant.

Funding

The Project has an approved budget of €300m for the initial capex, and €200m for O&M costs over the 20 year term. The initial capex will be part funded by an EU grant under the Connecting Europe Facility, with the remainder expected to be funded wholly or in part by debt finance. It is not yet clear whether EAC will invest equity into the Project – reference is made to EAC taking up to a 30% interest in the SPV at a later date.

Key issues

From our team’s experience of working on similar projects in Cyprus, key issues for the success of the Project may include:

  1. credit support to be provided by Cyprus stakeholders (DEFA / EAC / the government) and the successful bidder. It is interesting to note that the government of Cyprus will be issuing a government guarantee to support the debt financing;
  2. the possibility (and timing) of DEFA selling gas to other buyers in the future, and the implications for EAC’s gas take from the facility;
  3. EAC’s ability to pass through the costs it incurs by generating electricity from gas to electricity consumers under the Cypriot regulatory regime;
  4. the flexibility of gas supply required to meet the operational requirements of the Vasilikos plant (see the previous comments regarding the buffer solution). This will be particularly important given the expected trend towards increased levels of renewable generation and consequential impact on required flexibility of thermal plants on the system;
  5. the impact of additional delivery points for piped gas to other buyers/plants;
  6. the expected timeframe for the conversion of the Vasilikos plant’s turbines to gas, and commissioning of the gas-firing equipment;
  7. impact of any electricity system operator requirements – e.g. regarding new electricity market rules in Cyprus.

Dentons: Cyprus / LNG experience

Dentons has unparalleled experience of working on LNG projects in Cyprus, having advised DEFA for a number of years on the potential long term import of LNG to Cyprus, and subsequently on shorter term interim gas supply arrangements; and MECIT on the commercialisation of the Aphrodite Field in the Cyprus EEZ through the development of a proposed onshore LNG liquefaction and export project at Vasilikos.

The team has a particular focus in advising on international LNG import projects. Team members are advising, or have advised on, LNG import projects in Ghana, the Caribbean, Jamaica, Pakistan, Jordan and Malta.

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Natural Gas Public Company of Cyprus (DEFA) issues request for proposals for €500m LNG import facility

Iran Issues Pre-qualification for Upstream Tenders

Iran is said to be targeting an increase in oil production from 3.85 to 4 million barrels per day by the end of 2016. Iran is also hoping to start export of a new heavy oil, called West Karun, and which is expected to compete with Iraq’s Basra Heavy crude, which has gained a significant market with US and Asian refiners since its launch in 2015.

Iran’s new upstream contract, the Iran Petroleum Contract (IPC), was delayed by parliamentary amendments but is now scheduled for launch in January 2017. The State-owned National Iranian Oil Company (NIOC) has already signed up an IPC with local firm, Persia Oil and Gas Development Company, which is one of eight Iranian contractors authorised to team up with international joint venture partners. Whilst Iran’s production costs may be rock bottom, foreign investment (and currently foreign exchange) is needed to deliver scale and speed of development.

NIOC (on behalf of Iran’s Ministry of Petroleum) has published its “Pre-qualification Questionnaire for Exploration and Production Oil and Gas Companies,” to be completed by 19.11.16 in order for NIOC to publish a “Long List” of qualified applicants on 7.12.16. This list is intended to be valid for two years as a pre-requisite for participating in upstream tenders. NIOC intends to then invite a short-list of qualified applicants from the long list, depending on project type (Short List).

Long List applicants will be scored according to typical technical and financial criteria but with some additional emphasis seemingly echoing NIOC’s objectives, including “scale” and “internationality”. The greatest score (25%) is allocated under the heading “Reliability” to credit ratings. Whilst it seems unusual to delegate financial capability diligence simply to reliance on a third party credit rating agencies, it does reduce the internal resources needed to sift financial data. That said, a number of those with credit ratings (and by definition, public equity or debt) may not yet have the appetite for Iranian investments, whilst those privately funded entrepreneurs and companies with strong balance sheets, may not seemingly participate, assuming that NIOC doesn’t choose to deal with non-compliant applicants.

“Scale” is assessed in terms of production rates and wells drilled over the last three years, with technical capability assessed over the same period and broken down into experience type including conventional and fractured operations, and improved and enhanced oil recovery. Choosing the last three years of oil pricing where some operations may be moth-balled etc. may be significant, but given that it is unclear as to how applicants may be assessed competitively, this is perhaps academic, provided a minimum threshold is demonstrated.

“Internationality” is judged against an “applicant’s headquarters’ business and/or registration place” which is seemingly designed to allow some flexibility to avoid being disadvantaged by a tax headquarters and otherwise to make the best of an organisation’s international operations, and possibly from more than one headquarters, if one takes a literal interpretation of the punctuation.

For the purposes of the Short List, applicants are “requested” to specify their “priorities and interested fields” and whether they wish to act as operator or non-operator. This clearly allows room for judgement versus competitors as to whether applicants would wish to share their commercial position at the outset.

It seems likely that most of the credit-rated applicants who would qualify, are already known to NIOC / have registered their interest more or less formally. The collation of extra data should enable NIOC to take into account preferences, but to grade applicants and to allocate tender opportunities in a manner perceived as transparent and which tends to avoid the dominance of any particular constituencies. Whilst the application of such process could be regarded as a short-term disincentive to some with an incumbent position, it could also be used to justify the favouring of incumbents, safe in the knowledge that the market was tested first. Otherwise, such process is likely to be regarded more generally as a welcome codification of what is expected to be a hotly-contested new market for lower cost developments.

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Iran Issues Pre-qualification for Upstream Tenders

Why won’t UK shale be subject to the renewable energy community stake requirement?

As noted in our recent post on Shared Ownership, the UK Department for Energy and Climate Change (DECC) has published its Community Energy Strategy (Strategy) which anticipates that by 2015, it will be normal for new renewable energy developments to offer project stakes to local communities (and which could be enforced by an enabling power in the draft Infrastructure Bill 2014). At a recent renewable energy industry event, it was asked why shale developers are not similarly targeted by the Strategy to offer stakes to local communities?

Analogy to a new tax

In short, because it would likely be argued to be unfair. Shale developers have already paid and committed to fulfil minimum work obligations onshore under a petroleum, exploration and development licence, in order to have the right to explore for and later extract hydrocarbons from the sub-surface (and off the Crown). Any later requirement to give a royalty or equity interest to a local community, could be regarded as being analogous perhaps to an unexpected new tax. In addition, having to obtain DECC consent or adding say a community interest company (CIC) vehicle to a hydrocarbon licence, could be administratively cumbersome.

Misalignment of local opposition

That said, renewable developers may argue that buying or leasing surface land rights for renewable energy generation, and later having to give a stake to a local community, is little different philosophically. However, the current Strategy proposal is perhaps designed to address the apparent misalignment between national poll results (which are reported to suggest a majority are in favour of renewable energy); and local communities (who often resist wind and solar developments in their own localities). Such opposition is often then said to be reflected in local authority planning application refusals, which in turn reduces renewable energy development and impacts national carbon targets.

Reduced justification for compensation

By comparison, opposition to shale developments, is perhaps expected to be less driven by local planning or land-use opposition, as opposed to broader ideological and environmental concerns, which may not be as effectively addressed with active community participation – few well-heads will have the “wow factor” of a windmill. In addition, once DECC’s current consultation on granting horizontal drilling access rights (to ease shale and geothermal developments) runs its course (see our recent post Compulsory access rights “in the national interest”), then developers will possibly have less need for community alignment on specifically land-use environmental concerns. Indeed, the relative thickness of exploitable UK shale resources means that relatively few well-pad sites on the surface could be used to access large areas of sub-surface resource horizontally, causing little environmental impact (truck movements apart). This may reduce any justification for giving local communities a substantive share of the profits.

Conclusion: proactivity in hindsight

It is also important to note that the nascent shale industry, to the extent represented by the recently invigorated UK Onshore Operator’s Group (UKOOG), has perhaps already drawn some of the sting of potential community engagement regulation, by pro-actively suggesting well-pad and production payments (albeit modest in amount) for local communities. Whilst the renewables industry is more mature, numerous and with diverse interests, it may be noted that a sophisticated regulator is rarely motivated to act, except where market failure is perceived. Therefore, if the shale industry were to fail to implement the recommendations volunteered by the UKOOG, DECC may be tempted to re-assess the absence of unconventional developments from the Strategy and Infrastructure Bill’s proposals for community participation. In hindsight, now that DECC has seen a need to prompt the renewable energy industry into volunteering community participation, it appears less likely that community payments divorced from equity stakes or project profitability alone, will meet the regulator’s perception of community needs.

For further analysis on the potential application of UK and other international examples for tailoring legislation, farm-in and joint operating agreements in developing unconventional basins, please see our Shale Guide, recently presented and discussed over two days in Washington DC at a World Bank and OGEL symposium, aggregating the learning of representatives covering 18 countries.

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Why won’t UK shale be subject to the renewable energy community stake requirement?

Shale / Geothermal – Compulsory access rights “in the national interest”

The UK Department of Energy and Climate Change (DECC) has published a “Consultation on Proposal for Underground Access for the Extraction of Gas, Oil or Geothermal” (Consultation), which suggests a compulsory land access right below 300 metres.

Whilst such proposal was expected in relation to the UK’s developing shale industry (see our recent article: http://www.globalenergyblog.com/uk-shale-legislation-what-could-and-should-change-from-4-june), it is interesting to see such proposal aligned also to the non-fossil-fuelled geothermal industry.

Geothermal justification

Whilst geothermal technology may appear somewhat esoteric compared to shale these days, DECC notes that, unlike petroleum developments (which have compulsory land access rights for horizontal drilling etc. underground, pursuant to the Mines (Working Facilities and Support) Act 1966, as applied by section 7 of the Petroleum Act 1998 (Petroleum Act)), geothermal projects cannot use the Petroleum Act rights to access private land sub-surface (where a landowner withholds consent), and hence apparently need a new such right. Whilst geothermal power technology is perhaps not popularly associated with horizontal drilling, DECC note that directional drilling is required to locate the best point from which to withdraw water, and for separation of colder water reinjection, not to mention where district heating networks may require horizontal drilling.

Whilst the geothermal energy industry may be encouraged by such regulatory attention (albeit at the cost of a voluntary payment mechanism referred to below), it is worth noting that the geothermal industry does not yet have a licensing system of its own. At present, developers locating “hot spots” may be at risk of competitors also benefitting from such discovery. It will be interesting to see whether the geothermal energy industry is able to build upon such regulatory momentum. It may be noted that a potential geothermal licensing regime is currently under consideration in Scotland (see:  http://www.scotland.gov.uk/Publications/2013/11/2800/6).

Existing land access rights sub-surface

In any event, it is noted in the context of shale (and petroleum extraction more generally, both conventional and unconventional) that Petroleum Act compulsory land access rights already exist, but are untested in the current context and are time-consuming and costly (not to mention issues of having to trace ownership title from potentially numerous landowners). As is pointed out, however, existing land access rights (which require application to the Secretary of State where negotiated access rights are not feasible) need to meet any one of a number of criteria. One of these is where persons unreasonably refuse to grant access or demand unreasonable terms (which of course requires some subjective judgment to be applied, and therefore a route to potential judicial review of decisions made). Another is where the grant of the right is “in the national interest” (which appears more clear cut, once a precedent is established). In the Consultation, DECC makes the assumption that:

“In practice, a court is always likely to grant access because it would be expedient in the national interest …”.

New statutory access rights

Therefore DECC proposes a new statutory right of access to companies extracting petroleum or geothermal energy in land at least 300 metres below the surface (Statutory Access Right). It would not apply to Coal Bed Methane or Underground Coal Gasification development (which already have underground access under the Coal Industry Act 1994). The Statutory Access Right would involve a £20,000 one-off payment (which amount is apparently volunteered by the shale and geothermal industries) for each unique lateral well longer than 200 metres, although: “where lateral drillings vertically coincide payment will be made only once”. This presumably means that a horizontal plane of pipelines at the same depth would only attract one payment.

DECC’s preference is that payment would be made to a relevant community body rather than individual landowners (although it is noted that it may be difficult to ensure that relevant landowners are in fact among those wider beneficiaries of a community payment). To this end, as suggested in our previous articles, Community Interest Companies may be a suitable vehicle for such payments.

DECC would take a reserve power to enforce payment through regulation if such voluntary scheme were not honoured. A public landowner (and presumably community-based) notification system would be established, again based on the same industry voluntary “agreement”.

Whilst such proposals may cause concern amongst those opposed to unconventional developments, they will likely be welcomed by the shale industry in particular, which has requested procedural certainty and speed for sub-surface land access. Speed is clearly crucial, if test drilling is to begin to prove the commercial viability of UK shale production, before investors lose their appetite.

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Shale / Geothermal – Compulsory access rights “in the national interest”

Weald Basin oil – is it shale oil or oil shale? and why it matters

The UK Department of Energy and Climate Change (DECC) has published a study by the British Geological Survey of the Jurassic shales of the Weald Basin in southern England (Report). Unlike shale gas findings of a similar report published in 2013 for the Bowland-Hodder in northern England, the Weald Basin is said to contain oil:

“There is unlikely to be any shale gas potential, but there could be shale oil resources in the range of 2.2-8.5 billion barrels of oil (290-1100 million tonnes) in the ground, reflecting uncertainty until further drilling is done.”

A third study is also now said to be underway, and will apparently be completed in the summer of 2014. It will cover the Midland Valley of Scotland. Estimates will be made for both the oil and the gas “in-place” resources of the carboniferous strata of central Scotland.

Shale oil versus oil shale

The existence of shale oil (as opposed to gas) in the Weald Basin may come as less of a surprise given the existing conventional oil developments in the area (most notably the Wytch Farm oil field developed by BP). Nevertheless, extraction methods needed for shale oil (being oil produced from a shale reservoir), versus oil shale (being sedimentary rock from which Kerogen-based crude may be produced by heating), will be of interest to many. As the Report states:

“… oil shale is immature and can either be mined at or near the surface or retorted in situ at depth.”

It is understood that “retorting” involves heating oil shale in a process which causes oil and gas vapours to condense into a synthetic crude (and producing a solid coke-like residue). A heating source (generally gas or coal-fired) is needed for production. It is perhaps for this reason that the Report states that:

“Such oil shale extraction techniques make it very unlikely that it might be exploited at depth in the Weald Basin.”

Whilst this may suggest a surface or near-surface mining operation is necessary for extracting oil shale, if this is commercially and otherwise unviable, then it may be hoped that shale oil, is more abundant than currently estimated. The Report notes that:

“None of the Jurassic shales analysed …. has an ‘oil saturation index’ … of greater than 50 … [although] … it may be that some horizons within the Mid and Upper Lias, lower Oxford Clay and Kimmeridge Clay exceed the 100 required for the oil to be ‘producible’.”

In summary, unlike shale gas, where free and adsorbed gas may be extractable, with oil, only the free oil component is effectively producible. As such, the Weald Basin may only become economically attractive for unconventional oil production, if oil is found to be producible in commercial quantities as shale oil.

The Report’s findings are not therefore, perhaps likely to see the UK’s unconventional development focus shift from gas to oil just yet. Furthermore, given that most of the identified shale oil potential lies within existing licence areas, there may be limited opportunities for new entrants (unless existing licences are transferred or relinquished). It will of course be interesting to see the findings from the upcoming Scottish resource report, particularly given the significance to the Scottish independence debate. It is also interesting to note that in DECC’s publication “Underground Drilling Access” (published on the same day as the Report), that such Scottish resources are referred to as the “Oil-Shale Group” of central Scotland, which perhaps implies that the impending Scottish resource report may not flag significant quantities of hoped-for shale oil (as opposed to oil shale).

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Weald Basin oil – is it shale oil or oil shale? and why it matters

UK shale legislation – what could (and should) change from 4 June?

Land access under the Infrastructure Bill

According to reports by the BBC and the Financial Times, Whitehall sources have indicated that the Government plans to propose a new Infrastructure Bill in the Queen’s Speech on 4 June 2014. The Bill may provide for automatic access rights for certain shale developments below a minimum depth, and establish a landowner notification and compensation procedure (with a compensation cap).  Although the focus is expected to be on the facilitation of installation of export pipelines under private land, the legislation may also be relevant to horizontal drilling, well completion and stimulation techniques.

Discussions on horizontal drilling rights in the UK are, however, now well rehearsed. Drilling under private land without the owner’s consent is a trespass; compulsory access rights and compensation mechanisms already exist; but they are untested in the shale context, they involve potentially lengthy procedures, and their application could be subject to judicial review.  In the US, directional drilling techniques have been used (e.g. under Dallas Fort Worth Airport) to avoid unleased land and “set-back” restrictions.  Although the UK already has a long-established conventional onshore industry, such directional drilling techniques are not yet cited as a potential solution (and would not prevent the need to obtain a neighbour’s land access consent).

The land access issue is nevertheless often cited in the UK as a significant reason why, so far, early shale investments and recent consolidation amongst developers have not yet translated into drilling permit applications.  All appreciate that, unless test drilling commences in the UK, and the commercial viability of shale production is proven relatively quickly, further funding may not be forthcoming.  No wonder the Government is keen to be seen removing perceived blocks to development.

Whilst trespass is important, it is perhaps interesting that less focus has revolved so far around related land issues, such as residual and decommissioning liabilities, insolvency, remediation and security concerns. Therefore, if any Infrastructure Bill only tackles the issue of providing greater certainty to developers in relation to land access, there may remain some way to go in encouraging more wholesale shale developments by those who would welcome a further regulatory comfort blanket to overlay the existing, largely comprehensive framework of regulation.

UK onshore licensing round

Perhaps an equally pertinent topic for the time being is what may come to pass in the next UK onshore licensing round.

Whilst the issue of new licences in a new 14th onshore licensing round is not a foregone conclusion, the precursory strategic environmental assessment (which was subject to a Department of Energy and Climate Change (DECC) consultation that closed on 28 March 2014) stated that the option of awarding no licences in the 14th round is: “incompatible with the main objectives” of the Government, and is therefore perhaps unlikely.  Therefore, the issue of what the licence terms will look like is an interesting point of speculation.

The Government may be keen to avoid a two tier system which differentiates between conventional and unconventional developments if possible, particularly given the different approaches already applying to conventional developments onshore versus offshore (e.g. in relation to decommissioning treatment), and given the Wood Report’s recent call for greater integration.  That said, there is a contrary argument that some difference of approach is required, given the substantial depth of shale resources in the UK (being up to ten times thicker than in the US) and given that such thickness may justify multiple horizontal wells being drilled from a single well-pad.  This would suggest that provision should be more formally made to allow multiple developments (conventional or unconventional) to proceed under the same land footprint, at differing depths or horizons, in order to maximise recovery from the resource over a given land area.

It is perhaps also worth considering some example terms from the latest (2008) 13th UK onshore Petroleum Exploration and Development Licence (PEDL), and associated model clauses set out in legislation (Model Clauses), in order to highlight areas which would perhaps suit amendment in the unconventional context:

  • Mandatory relinquishment of 50% of the licence area at the end of the initial term of six years is clearly sub-optimal for shale developers, who need certainty over an area throughout a drilling campaign (although relinquishment may be avoided on a bespoke basis where the regulator considers it necessary to recover petroleum, under Model Clause 4(5)).
  • The second term in a PEDL is currently five years, with a distinct 20-year production period thereafter.  Similarly, this separation does not lend itself well to a pilot / appraisal phase (which is likely to include some production).  Re‑alignment along the lines of a dual appraisal phase, followed by a commercial production phase, may be more suitable.
  • The typical work commitment for the initial term (e.g. drilling one, typically vertical, well and conducting seismic work) could do with tailoring to the unconventional situation, perhaps to include ongoing development obligations after initial appraisal.  Indeed viable seismic may be precluded by landscape issues.  One approach from the US, which may be adapted in shaping work commitments (and indeed relinquishment-related issues), is allowing a large block to be held, so long as the operator maintains a “continuous drilling programme”, meaning that a new well must be started within, say, 180 days of completion of the prior well.  A failure to meet the drilling deadline typically results in the loss of all acreage outside the acreage attributable to the existing wells.  Many private agreements in the US (wishing to encourage drilling and hence maximise economic recovery) incorporate similar arrangements into their commercial lease arrangements.
  • Use of terms like “Oil Field” (which means strata forming part of a single geological petroleum structure, according to Model Clause 23(1), which deals with unitisation), in the context of requirements to unitise, conduct petroleum measurement and elsewhere, could have unintended consequences when applied to the unconventional context.
  • Whilst Model Clause 27 treats data required to be provided by a licensee to DECC as confidential, 27(d) allows the relevant Minister, the relevant local council and others, to publish: “any of the specified data of a geological, scientific or technical kind” after as little as four years.  Clearly this may be of concern to operators and other owners of sensitive intellectual property who are keen to keep such data confidential.  There may be arguments to suggest that the nature of data necessary to commercially “unlock” a shale, for example, should in fact be treated as proprietary and therefore be subject to greater confidentiality restrictions.
  • Perhaps the most stark example of a licence term which may require amendment in the unconventional context, however, is Model Clause 19(1)(d) under the heading “Avoidance of harmful methods of working“, which requires licensees to: “prevent the entrance of water through Wells to Petroleum-bearing strata except for the purposes of secondary recovery…“. Few would argue that water injection for hydraulic fracturing amounts only to secondary recovery, and therefore an amendment to remove any ambiguity would appear prudent.

Whilst regulators may be happy to take a liberal interpretation of existing licence terms when applied to licensees and operators, those decisions may be subject to greater scrutiny by those opposed to shale developments, potentially opening the door to judicial scrutiny.  It remains to be seen whether the Queen’s Speech on 4 June (or the 14th licence round) will put some minds to rest.

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UK shale legislation – what could (and should) change from 4 June?

A New UK Oil and Gas Regulator by 2015?

Summary

The title given to Sir Ian Wood’s “UKCS Maximising Recovery Review: Final Report” (published on 24 February 2014), should ensure that his name is immortalised as the abbreviation most will use, the “Wood Review”, and rightly so. This former chairman of oil field services company Wood Group has become a figure-head for reform and has set a CEO-style vision, in addition to his Government remit to make recommendations to: “enhance economic recovery of oil and gas reserves in the future”.

With this in mind, the Wood Review is not overly compromised with detail. The central proposal is for a new, independent, and much more proactive regulator to maximise economic recovery (MER).  This could be criticised as fragmenting current regulation, but Sir Ian’s pragmatic rationale is clear: “a new body…to focus solely on MER will give a clear signal. The Review believes that simply increasing the resource…within DECC is likely to be perceived as a re-badging with little material change.”

Context

The imperative for MER is production apparently falling by 38 per cent between 2010 and 2013 and a sharp decline in exploration and discovery.

Given the right “stewardship,” the UK is said to have the potential to recover an additional 3-4 billion barrels of North Sea oil over the next 20 years, with a resultant £200 billion boost to the UK’s economy.

The final Wood Review is consistent with and builds upon its Interim Report, published in November 2013.

Obstacles to overcome

The Wood Review identifies outdated “light touch” regulation as a key hindrance to the exploitation of hydrocarbons in the North Sea. A regulatory regime designed for an era of large fields and large operators has apparently not evolved to adapt to the new reality of a basin with over 300 fields, much smaller new discoveries, many marginal fields and far greater interdependence in exploration, development and production.

Specific obstacles to growth highlighted in the Review include fiscal instability, insufficient collaboration between industry players in respect of third party use of infrastructure, a lack of sharing of geophysical information, excess time spent on commercial and legal negotiations and inadequate use of technology (including Improved and Enhanced Oil Recovery (EOR)). Floating Production Storage and Offloading vessels are for example noted to have higher operating costs and poorer field recovery than using existing infrastructure where available. Over 20 instances in 3 years of “operators” failing to agree terms for access to processing and transport infrastructure, has led to more expensive / lower recovery developments.

Key recommendations of the Wood Review

The Review advocates a tri-partite strategy involving HM Treasury, industry and the proposed MER regulator. Whilst collaboration may be implicit, it is notable that the involvement of existing regulatory bodies is not emphasised. Some re-alignment of regulatory responsibility is suggested with the new MER regulator perhaps being given responsibility for carbon capture and storage, and with a potential on-shore remit. The Review also recommends new sector strategies be developed for: exploration; asset stewardship; regional development; infrastructure; technology and decommissioning.

The Review envisages that the proposed new MER regulator would be encouraged to make more robust use of existing enforcement powers and may be given new powers or access to licensees, both in the practical sense (for example by being able to attend operational and technical meetings; make recommendations; have greater data access; and to implement a “non-binding” dispute resolution function), and by way of potential new licence terms (relating to maximising economic recovery, achieving acceptable production efficiency and agreeing collaboration on cluster developments). It is further suggested that consideration of past MER performance, should be specifically taken into account for future licence applications. Formal sanctions to encourage MER compliance may include a system of issuing private and public warnings, before removal of operatorship or suspension or termination licences. Interestingly, it is said that the MER regulator should have the right to apply sanctions to the whole consortium or just those who are deemed to be failing to meet licence obligations, or indeed, MER requirements. Whilst it appears there is significant detail to be ironed out here, the collective responsibility intention is notable.

Flexibility

There is also a recognition of a need for flexibility where necessary. The four year exploration and four year development terms in Traditional Seaward Production Licences are noted as appropriate for mature areas, but the Review suggests that six year periods are more suitable for frontiers like the West of Shetland, where the drilling season is short, and in High Pressure High Temperature plays. It is said that licensees shouldn’t be compelled to drill commitment wells where new information suggests they would be unviable. The flexibility theme is also discussed in the context of the almost exclusively gas producing Southern North Sea, which is in danger of apparently premature decommissioning, given the lower market value of gas.

Competitive disadvantages of the UKCS versus the Netherlands are another interesting theme and is, in part, attributed to the Dutch Government’s active ownership of infrastructure. Differences in commercial models are also noted whereby, for example, NOGAT BV (whose business model is solely to operate pipelines and processing facilities) actively seeks to attract new transport business, versus the apparent reluctance of UKCS operators to facilitate third party infrastructure use business as an adjunct to their core production business.

Fiscal incentives

Such issues are intended to be bolstered by HM Treasury’s better use of: “fiscal levers to incentivise MER”, perhaps including: extension of field allowances to incentivise EOR; or incentives for seismic and the drilling of exploration or less prospective wells by operators who currently lack production. In addition, a need for commitment to a simpler and more stable fiscal regime is acknowledged (although tax is beyond the specific remit of the Wood Review).

What is next?

Government and industry appear to publically welcome the initiative, which is to be industry-funded. Indeed, Ed Davey (Secretary of State for Energy) has announced that legislation to implement the new body, will be introduced in the fourth parliamentary session (ie. autumn 2014) but it would be expected to become law in 2015, and may be dragged out by a need for secondary legislation. Ed Davey has hinted at an informal “shadow” arrangement in the meantime. Such break-neck speed perhaps seeks to capitalise on the Review’s current good will, and will hope to minimise potentially significant industry delay in making new investments, pending uncertainty as to the new regulations.  It may also reflect the UK Government’s desire to show oil and gas policy leadership before September’s referendum on Scottish independence, and the spring 2014 publication of detailed Scottish oil and gas proposals for maximising economic recovery, which also intends to consider the Wood Review. Time will tell whether all remain so keen, once detailed provisions take effect, particularly given the Review’s criticism of some current areas of apparent self interest which are to be targeted.  As currently proposed, reforms may touch all areas of the UK oil industry from operators down, both on and off-shore.

 

 

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A New UK Oil and Gas Regulator by 2015?