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Offshore Energy Bulletin, June 2013

In this issue: Importation of offshore ships in Australia; OTC 2013 - is deepwater drilling making a comeback?; Insurers beware: BP wins US$750 million additional insured claim; Impact of "The Astra" on Supplytime and Towhire; Delays in Offshore Wind Farm Construction; Conferences & Events.

Importation of offshore ships in Australia

Owners and charterers of ships servicing the Australian offshore energy sector may be adversely affected by a recent and unforeseen development in relation to the Australian Customs and Border Protection Service’s (Australian Customs) approach to the importation of ships.

In a radical policy shift, Australian Customs has abandoned the “90 day rule” that was previously applied to foreign ships trading in Australian waters, and adopted a very narrow and arguably flawed interpretation of “importation” under Australian customs legislation, which is premised solely on whether a ship has “entered into the commerce of Australia”. This new approach does not take account of the particular circumstances and period of a ship’s presence in Australia, nor of the intentions of the operator of the ship. As a result some ships servicing the Australian offshore sector may now face the risk of being imported.

It is understood that the policy shift is Australian Customs’ response to the revised cabotage regime that came into effect in July last year, one of the stated objectives of which is to facilitate “the long term growth of the Australian shipping industry” – which is currently in a parlous state. However, neither the current nor previous cabotage regimes had mandatory application to voyages between ports within an Australian State or Territory (“intra-state voyages”), or any application at all to voyages between offshore installations and mainland ports (“shuttle voyages”).

In other words, foreign ships undertaking intra-state voyages and shuttle voyages (being the voyages most commonly undertaken in servicing the offshore energy sector) are not required to hold a ‘Temporary Licence’ under the new cabotage legislation. Notwithstanding that there has been no change of position regarding the regulation of these voyages under the new cabotage regime, Australian Customs without prior warning has implemented a stringent approach to the importation of ships that are not covered by a Temporary Licence (which in the case of shuttle voyages is not capable of being obtained).

The policy shift has the potential to result in absurd outcomes. For example, Australian Customs may determine that a ship which has been in Australian waters for less than 48 hours has been imported because it is trading without a Temporary Licence, whereas a ship that has been operating in Australia for several months will not be imported because a Temporary Licence has been issued for the trade it is engaged in.

The current uncertainty caused by the policy shift is having a significant negative effect on the Australian offshore oil production industry at a time when projects are already under substantial pressure due to cost overruns and delays. The voyages most likely to be impacted are intra-state heavy lift movements of project cargo, e.g. on the Western Australian coast, and the carriage of oil loaded from FPSOs for discharge at Australian mainland refineries.

One consequence of the policy shift is to make it less profitable for Australian offshore oil producers to supply Australian refineries. Ultimately, this seems likely to result in the curious position that all crude produced from installations in Australia’s EEZ will be exported, with Australian refineries importing their crude requirements.

Hopefully, a sensible solution can be achieved in the near future. In the meantime, owners and operators engaged in these Australian trades should proceed with extreme caution and appraise themselves of the options available to minimise the risk of their ships being imported.

OTC 2013 – is deepwater drilling making a comeback?

Following the events in the Gulf of Mexico in April 2010, one might have expected that deepwater drilling may take a while to return to the level of activity seen pre-Macondo. For those who attended the Offshore Technology Conference (OTC) in Houston this May, this was clearly not the case. Over 100,000 people descended on Houston for the week to see and hear about the latest advances in everything to do with the oil and gas industry.

There were some interesting statistics being advanced:

  • One oil major expects the rise in total global energy demand to be in the region of 36% by 2030 – the equivalent of adding another US and another China to current global energy needs over the next 17 years. This potentially means that the world could need to produce 16 million more barrels of crude oil a day.
  • This year, it is expected that the US will surpass Russia and Saudi Arabia as the world’s largest crude oil producer.
  • The shale gas revolution is set to continue as fracking technology improves. The US Energy Department projects that in the US alone, gas production is likely to grow 44% between now and 2040.

A key theme that emerged at OTC 2013 was establishing the longevity of existing oil and gas fields through the use of new technologies such as seismic acquisition and data interpretation, enhanced oil recovery and advanced field technology. Despite the North Sea being one of the oldest oil and gas producing areas, one oil major estimates that it has only tapped into 40% of its reserves, and that better seismic profiling has already resulted in an increased recovery rate from existing wells.

Another theme at OTC 2013 was the ongoing discovery and development of new oil and gas fields around the word. In Angola, one of the newest areas to be explored and developed, large fields such as Greater Plutonio are starting to come online. For example, BP’s PSVM FPSO will tap into four fields simultaneously, in water depths of over 2000m. With 75,000 tons of subsea equipment beneath it, the footprint of the subsea system alone is larger than Greater London, at 600 square miles.

Enormous investment continues in the offshore energy sector. One oil major announced that it is planning to spend $12 billion in Azerbaijan between 2013 and 2017, and has recently installed the largest jacket ever in the Caspian Sea, in the Azeri-Chirag-Gunashli field. Returning to the Gulf of Mexico, BP alone is planning to invest between $4 and $5 billion a year in the region until 2020, as advances in technology allow companies to explore ever deeper geological strata.

This is all good news for participants throughout the offshore oil and gas industry, and is likely to correspond with increased demand for support services including finance, legal and insurance.

Insurers beware: BP wins US$750 million additional insured claim

In March 2013, the US Fifth Circuit Court of Appeals ruled in In Re: Deepwater Horizon1 that BP was entitled to coverage as an additional insured under Transocean’s insurance policies, giving BP access to US$750 million under Transocean’s insurance to cover pollution-related liabilities arising out of the Deepwater Horizon oil spill, even though Transocean was not responsible for those liabilities under the underlying contract.

Under the underlying Drilling Contract, Transocean was responsible for, and was obliged to indemnify BP against, liabilities for pollution originating on or above the surface of the water. BP was responsible for, and was obliged to indemnify Transocean against, all other pollution.

The Drilling Contract also required Transocean to maintain various insurances, and provided that BP should be “named as additional insureds in each of [Transocean’s] policies, except Workers’ Compensation for liabilities assumed by [Transocean] under the terms of this Contract.”

The relevant insurance policies held by Transocean contained materially identical provisions, and were accordingly treated as one for the purposes of the Court’s analysis. The parties agreed that the policies provided some insurance coverage to BP as an additional insured. The issue in contention was the scope of BP’s coverage.

The insurers argued that the additional insured provision in the Drilling Contract limited BP’s coverage to liabilities specifically assumed by Transocean under the Drilling Contract (“misdirected arrow” cover). However, the Court found that “This argument is simply not persuasive given how Texas law has developed.” Under Texas law, to discern whether a commercial umbrella insurance policy “purchased to secure the insured’s indemnity obligation in a service contract with a third party also provides direct liability coverage for the third party,” one must look to the “terms of the umbrella insurance policy itself,” rather than those of the underlying service contract.

The Court considered the 2005 case of ATOFINA, which dealt with substantially similar policy wording, in which the Texas Supreme Court said that “where an additional insured provision is separate from and additional to an indemnity provision, the scope of the insurance requirement is not limited by the indemnity clause.” On this basis, the Court held that there was also no relevant limitation to BP’s coverage under the policy as an additional insured, provided the insurance provision and the indemnity clauses in the Drilling Contract were separate and independent.

In deciding this question, the court applied the reasoning in ATOFINA2 and concluded that the two relevant provisions (one requiring Transocean to obtain coverage for its contractual liabilities, another simply requiring Transocean to name BP as an additional insured) were separate and independent.

Accordingly, since (1) the policies did not impose any relevant limitation on the extent to which BP was an additional insured, and (2) the additional insured provision in the Drilling Contract was separate from and additional to its indemnity provisions, the court found as a matter of law that BP was entitled to coverage under each of Transocean’s policies as an additional insured.

A particular feature of Texas law is that any ambiguity in an insurance coverage provision (particularly exceptions or limitations on liability) are interpreted strictly against the insurer and in favour of the insured, provided that interpretation is reasonable – even if the insurer’s interpretation is more reasonable than the insured’s. Whilst it remains to be seen, therefore, whether this decision will be followed in other jurisdictions, insurers would be well-advised to scrutinise their policy wording to ensure it places the intended limits on the scope of additional insured coverage.

Impact of “The Astra” on Supplytime and Towhire

The recent decision of the English High Court in the ASTRA is generally expected to have profound effects on hire payments and termination rights under time charterparties. Are timecharter-based contracts in the offshore sector, such as Supplytime and Towhire, likely to be affected?

The Astra was a ship fixed on a five year time charter on an amended NYPE 1946 form. Clause 5 of the charterparty required punctual and regular payment of hire, and an anti-technicality clause was incorporated into the charter. Charterers defaulted on several occasions, culminating in owners sending an anti-technicality notice, subsequently withdrawing the vessel and claiming that charterers were in repudiatory breach.

When the owners were successful at arbitration, the charterers appealed to the High Court. Although Mr Justice Flaux dismissed the appeal, he made some important comments about the underlying nature of the obligation to pay charter hire. In particular, he indicated that the charterers’ obligation to make punctual payment of hire under clause 5, especially in light of the anti-technicality clause, amounted to a condition of the contract, breach of which would entitle an owner to terminate the charter and claim damages for future loss of earnings. This represents a significant turnaround in opinion. Previously it was widely believed that non-payment of hire would allow an owner to withdraw the vessel and claim unpaid hire only up to the date of withdrawal – not future losses.

Clause 10 of the “Supplytime 1989” form permits the owner to suspend performance whilst payment remains due, and withdraw the vessel for late payment of hire. By comparison, clause 12 of the “Supplytime 2005” form contains much more prescriptive provisions relating to disputed invoices and late payment of hire. In particular, clause 12(f)(i) contains a grace period provision, which is designed to avoid the abuse of an owner’s right to withdraw where delays in remitting hire are through no fault of the charterers.

The fairly loose wording of the 1989 form suggests that there may be room for the application of the ASTRA decision: owners could potentially argue that the obligation to make punctual payment of hire amounts to a condition of the charter. On the other hand, the 2005 form clearly stipulates the parties’ agreement as to the consequences of late hire payment, and so it seems unlikely that the ASTRA will have any significant impact on the parties’ rights and obligations under the 2005 form.

Clause 3 of the “Towhire 2008” form is virtually identical to clause 2 of the former 1985 version of the form, and simply states the daily rate of hire and that payment should be made in advance. The clause does not state what will happen in the event of late payment of hire and, unlike the NYPE 1946 form, it does not expressly require punctual and regular payment of hire. Given the difference in wording, the effect of the ASTRA decision is more open to debate. Owners may seek to argue that clause 3 is a condition, breach of which would entitle them to terminate the charter and claim damages including for future loss of earnings. Naturally, charterers would argue to the contrary, to avoid such exposure.

Which party is correct will depend on how the English courts interpret and apply the ASTRA decision, which will only become clear over time. For now, parties are advised carefully to review the hire payment obligations in their charters and consider how their position might be affected by this recent High Court decision.

For further information on the ASTRA decision please see our recent briefings: “Payment of hire is a condition – an end to a charterer’s ability to deduct from hire” at, and the Astra Appeal Status and Update at

Delays in Offshore Wind Farm Construction

The market in Northern Europe for offshore wind farm construction remains vibrant, with much of the second round of the UK development pushing ahead in the 2013 working season. The level of activity means that some areas are currently suffering ‘pinch points’ of supply where there is a shortage of workboats, barges and other specialist equipment.

This restriction in supply has enabled suppliers and contractors to negotiate more favourable terms in respect of project risks: in particular their liability for ground conditions, adverse weather and tidal conditions. The dynamic nature of the environment for offshore works means that parties must carefully consider any clauses in which these risks are apportioned.

It is now usual practice to allocate weather risk by reference to an agreed baseline: a table of agreed parameters for certain operations, with their appropriate Significant Wave Height and Wind Speed measurements, along with the size of the ‘window’ within which certain activities will be carried out. Additionally, the parties may agree that a certain number of adverse weather days will inevitably take place, and be programmed for by the contractor.

Weather events outside the agreed scope will be deemed unexpected and therefore outside the contractor’s responsibility. This means that a contractor will be entitled to claim for the necessary extension for carrying out the remaining works (avoiding liability for delay damages), and may also have an entitlement to recover the additional costs incurred, such as vessel standby, crew costs, etc.

However, the apparently simple allocation of risk for adverse weather events may still cause complication in terms of its practical consequences. This is because a relatively minor change to an offshore works programme may have a significant impact on the critical path for the remainder of the works. It may, for example, become necessary to adjust the programme to accommodate new weather windows, which is a significant task in any live project. This is further complicated when additional events of delay occur at a later stage, which again will require assessment in terms of their impact on the critical path.

Despite the skills to be found in the offshore construction industry, such herculean powers of assessment in a live project, within an existing programme, will usually be beyond a mortal project manager. This will result in claims simply being ‘parked’ by the parties and swept up at the end of the project. Such an approach may have its merits, but does not lend itself to cost certainty, and the negotiating power of the parties may also be significantly different at completion.

Alternative approaches to assessment may include the introduction of Adjudication Boards or other, independent third parties charged with imposing a binding assessment of time and cost consequences in very short timescales, to permit the project to continue.

Whatever method is adopted, the complicated environment of wind farm developments will require greater consideration of delay management to avoid the issues that have affected so many projects to date.


  1. In re Deepwater Horizon, No. 12-30230, 2013 WL 776354 (5th Cir. Mar. 1, 2013)
  2. Evanston Ins. Co. v. ATOFINA Petrochemicals., Inc., 256 S.W.3d 660 (Tex. 2008)

Conferences & Events

Energy & Resources Seminar
HFW Perth, 10 July 2013
Presenting: James Donoghue, Hazel Brewer, Matthew Blytcha, Julian Sher

9th Annual International Colloquium: Maritime law – offshore contracts and liabilities
Swansea, 9–10 September 2013
Session Chair: Paul Dean

London International Shipping Week – HFW Piracy Seminar
HFW London, 11 September 2013
Presenting: James Gosling, Richard Neylon, Elinor Dautlich

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