What sort of sting is in this tale?

May 1, 2011

Multi-client specialist TGS took the marine seismic business by surprise last month with the purchase of Stingray Geophysical, a UK-based start up company focusing on seismic-based permanent reservoir monitoring (PRM). Andrew McBarnet discusses what prompted the move.

There's been quite a bit of headscratching in the marine seismic community since TGS announced in April that it was acquiring UK-based Stingray Geophysical, a company which has developed a seismic-based permanent reservoir monitoring (PRM) system using fibre-optic cable buried in the seabed.

TGS explained the move as a means to gain a strong position in the rapidly growing market for permanent reservoir monitoring (PRM) solutions and ‘to substantially increase TGS' addressable market through access to production seismic spending from large international oil companies as well as national oil companies (NOCs), while maintaining its successful asset light model.'

Whatever the summary explanation, this is such a departure for TGS that it raises some interesting questions. For example, could it be that the company is beginning to worry about the long term sustainability of its business model, which up to now has been golden, the envy of all its competitors. For more than a decade, TGS has successfully negotiated the notorious cycles of the marine seismic market to the extent that almost every quarter during the period has been profitable, a record no other company can match.

The secret of the company's success, although there is nothing hidden about it, has been its strategy of focusing exclusively on building a worldwide seismic data library based on multi-client seismic surveys without getting into vessel operations. Its skill has been to consistently identify prospects ahead of the competition and put together cost effective multi-client projects which oil companies are willing to pre-fund, in part or in total, thereby reducing the risk to TGS. Once the survey has been undertaken on the company's behalf, TGS processes the data into a sellable data package. Although the end product is not exclusive, companies will buy this shared cost data because it is much cheaper than a proprietary survey.

The magic formula is that TGS has always refrained from owning or operating vessels. In other words, it has none of the overhead associated with managing a marine seismic fleet. This has proved a huge benefit over time. All its surveys are carried out by vessels chartered on short-term contracts usually at a very favourable price. If the market for marine seismic surveys is soft, then TGS gets a good price for its charters, and when over-capacity rules as is the case right now, the company can again squeeze down the price it pays.

One scenario in which the TGS multiclient model comes under pressure is when there is a boom and demand for vessels outstrips supply. Then availability of vessels for charter is limited and the price skyrockets making its multi-client programmes more difficult to plan and potentially less profitable. This is exactly what in 2007 moved TGS to do something completely out of character. It decided that the best way to beat the scramble for a limited supply of vessels was to buy an existing marine seismic contractor with a ready-made fleet. The target of its interest was the newly formed Norwegian company Wavefield-Inseis, which was rapidly building its vessel count.

In the end, the Wavefield transaction died in a hotbed of recriminations and in early 2009 the company eventually fell to CGGVeritas at nearly half the price of what TGS had offered. All that is water under the bridge, except that it indicated a willingness on the part of TGS to consider a different business model. The purchase of Wavefield would for the first time have put the company on a level playing field with every other marine seismic contractor. It's not telling stories out of school to say that the competitors could scarcely conceal their glee at such a development. They couldn't wait to see how the company coped with all the attendant headaches and costs of having a fleet to manage.

TGS is generally considered to have dodged a bullet by not buying Wavefield. The combined entity would have controlled a seismic acquisition fleet comprising six 3D and seven 2D vessels on short or long term charter, certainly a very viable size of fleet. But CGGVeritas has found the melange of Wavefield vessels, few of which were custom-built for 3D seismic, to be a burden as well as a blessing as it has had to spend capital on standardising equipment to increase operational efficiency. There were also a significant number of former Wavefield management defections which cannot have been helpful. Whether this would have happened if TGS had taken over the company is a matter of speculation.

So we come back to the question as to what possessed TGS to invest in the nascent PRM market through the acquisition of Stingray. It's perhaps best to make clear from the onset that the money involved is a drop in the bucket for TGS, so there is very little financial downside. The company is paying the investors in Stingray an initial $45 million and incremental payments of up to $35 million based on the success in commercializing the technology, ie very little upfront risk. TGS in February was showing nearly $300 million in cash; it has been buying back its shares and paying dividends which are all indications of a companyin rude health. During a conference call, TGS CEO Robert Hobbs indicated that the operational costs of running Stingray would be negligible, although it was less clear what additional R&D expense might be involved.

The Stingray buy appears to be more about a very successful company wanting or needing to add new markets to its portfolio. In this respect, it is being entirely consistent with previous initiatives. Since the purchase of UK-based BiPS in 1998, the company has been making efforts to build up its data processing capacity. In 2004 it bought NUTEC Energy, and in 2007 added PDS with this goal in mind. It has also been establishing a Geological Products division to build a digital well log online database, kicked off by the purchase in 2002 of A2D Technology.

The expansion of its processing capacity makes sense for TGS in terms of being able to enhance its multi-client data offerings as well carry out third party contract work. As such this has not been an entirely new business like the Geological Products division, the abortive attempt to buy Wavefield or purchasing Stingray. At the time of the Wavefield merger manoeuvres, TGS made clear what its priorities were. Some of these exactly echo its reasoning for making the Stingray purchase, namelyenhanced market access, NOC exposure, increased processing revenue and access to new technologies. Note that if TGS had acquired Wavefield, it would actually have inherited the fibre-optic based Optoplan PRM system not dissimilar to Stingray's offering, now in commercial operation for the first time on the ConocoPhillips Ekofisk field under the management of CGGVeritas.

TGS clearly has a vision beyond multiclient operations, and it's not difficult to understand why. Concentrating on multi-client seismic means that its main business is locked into exploration, this at a time when the consensus is that the easy to find oil has gone and that much of our future supply will come in the form of enhanced recovery from existing reservoirs. TGS in the past has won a lot of its business carrying out sponsored surveys ahead of offshore licensing rounds providing data upon which companies can bid. This has worked well especially offshore UK, Norway and in the Gulf of Mexico but elsewhere in the world the opportunities are more sporadic, especially where NOCs commission their own pre-licensing round surveys and then make the data data available to interested oil companies.

Make no mistake, however, TGS is still having a good run. Recently it signed letters of intent with CGGVeritas andnew contractor Dolphin Geophysical to charter two 3D vessels for work offshore Europe this summer. The company is doing good multi-client business in Indonesia and elsewhere, some of it involving reprocessing of old data using improved techniques. It is also the case that as seismic acquisition technology advances, so oil companies want to re-visit some of their acreage to see whether anything has been missed. A case in point is wide-azimuth surveying of salt prone areas such as the Gulf of Mexico and offshore Brazil, which from a cost perspective is particularly suited to multi-client programmes.

But an issue for all public companies is that insatiable demand from shareholders for evidence of growth. Looking over the horizon TGS management may suspect that multi-client surveys do not offer much opportunity for expansion. It is not as though they have the market sewn up. TGS does not even have the biggest seismic data library, and all the main marine seismic competitors are on the look-out for opportunities as multi-client can be very profitable. Just recently Dubai-based Polarcus announced that it was to undertake its first multi-client project.

In weighing its options, TGS has identified that only 20% of E&P expenditure by oil companies is on exploration, and that only 20% of this is spent on seismic with drilling taking up 60% and leasing costs 20%. Reviewing the 80% of E&P spent on production, seismic and other unspecified applications make up 20%, with drilling (20%), FPS (20%), SPS (20%) and SURF (20%).

The conclusion that the company came to is that it needed to find a way of tapping into the production seismic market. What has puzzled people is why it chose the purchase of Stingray as its first step in this direction. The company, with 11 employees, is still somewhat embryonic, with no serious commercial transactions to its name. Its pedigree is impressive enough, financed by heavyweight venture capitalists such as Energy Ventures, Chevron Technology Ventures, Energy Capital Management/ Statoil Venture and Cody Gate Ventures. It has been developing a fibre optic optionfor PRM which originates from the UK defence business, and is essentially vying with competing systems offered by Petroleum Geo-Services and CGGVeritas, both of which have won their first contracts, offshore Brazil and Norway respectively.

In a sense Stingray is an unknown quantity until it wins some work for its Fosar PRM system. Being owned by a substantial marine seismic player will certainly add to its credibility. But it is fair to suggest that TGS does not have the same operational credentials as PGS and CGGVeritas to back Stingray, and indeed has no known R&D committed to life of field seismic. Stingray's equipment deployment contractor in the event of a contract for its PRM system would have been Bergen Oilfield Services.

TGS says that it wants to establish a strong foothold in what it describes as the rapidly growing market for PRM solutions. In a presentation last month the prospective market (the number of potential upcoming PRM opportunities worldwide) shows an increase from around $375 million in 2011 to $1.4 billion by 2015. Even allowing for the fact that these estimates come from Stingray, you would think that TGS is bound to land a winner or two.

Yet it cannot have escaped the notice of TGS management that the market for life of field seismic or PRM is fraught with uncertainties, confirmed by a recent workshop in Trondheim, Norway (‘G&G Notebook', OE March). There are only a handful of these projects worldwide, most of which were implemented by BP using a conventional cable system from OYO Geospace. The two fibre optic systems are only in the early stages, so few conclusions can be drawn on their value. The word in the industry is that interest is very much confined to a few major oil companies. They do not discount the potential upside of PRM technology in terms of the frequency and quality of data potentially available and the possible addition of recovered oil from better reservoir management strategies based on the monitoring information. However, they continue to be put off by the high upfront costs compared with known quantities such as towed streamer 4D seismic and temporary subsea recording systems using nodes or ocean bottom cable, all of which produce usable results.

At best the installation of PRM systems can be expected to be sporadic, which makes it hard to build a sustainable business. TGS has recognised this in that it would only invest in cable manufacture when a contract has been agreed, so it keeps to its mantra of remaining asset light. Before the takeover, Stingray also introduced the concept of smaller, targeted PRM systems for floodfront and fracture monitoring which would be more affordable for oil producers.

Even on an optimistic scenario, you have to ask where the money can be made from a PRM system beyond the initial manufacture of the recording equipment and subsequent installation on the seabed, where the only role for TGS would be in a management capacity. Acquisition of the data over the installed network of receivers will be no big deal, so TGS must be eyeing the potential data processing requirement as the money earner. This still does not add up to a substantial commercial activity it is repeat business.

In this context it is interesting to reflect that Schlumberger, the seismic industry's biggest company, could at any time have stepped in and acquired Stingray. Yet it continues to show little public interest in PRM as a business proposition (although you can be sure that the company is keeping close tabs on everything that transpires).

The real rationale for TGS's entry into the PRM market may therefore be less about reservoir monitoring and more a declaration of intent by the management to take the company more into production seismics. It apparently believes that Stingray will prove a door opener for discussions on reservoir seismic business with international oil companies and particularly NOCs.

As a strategy, it is different, but who is to say that it is wrong? OE

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