Can you provide an overview of BP Trinidad and Tobago’s contribution to the global BP network?

Calculating Trinidad and Tobago’s importance to BP’s overall production depends on whether or not BP includes or excludes Russia from its calculations. Traditionally, Russia has been the largest contributor to our network, but when the sale of BP’s Russian assets is finalized, this is likely to change, to the relative advantage of Trinidad’s contribution. However, if you separate our various North American and Gulf of Mexico operations, Trinidad and Tobago is by far our largest net producer, currently producing around 400,000 bpd. This reduction from our numbers some years ago is due in large part to the integrity work we are carrying out at the moment, which is set to be completed in 2013.

There has been an overall downturn in production in Trinidad and Tobago; what do you think are the contributing factors to this?

There is a misperception that the downturn in production is linked to American discoveries of shale gas; this is not true. There is a relationship in the change of our markets, but not in the levels of production. We have not had a problem selling the amount of gas being produced to various markets, but we have certainly seen more diversity in the markets we supply. The largest contributing factor to the downturn has actually been the integrity work that we are conducting. Because of BP’s contribution to Trinidad and Tobago’s overall production, our integrity work has a very visible impact on our numbers, but similar work is happening across the sector at the moment. We expect that as production comes back on line in 2013, it will do so with both increased quantities and efficiency.

With substantial potential remaining even after more than 100 years of production, Trinidad and Tobago presents an interesting story; do you think that investors understand the opportunities offered here?

Investors in Trinidad and Tobago certainly do understand the opportunity here, and foreign investors are increasingly beginning to do so as well, as evidenced by the latest bid round. Newer players are getting involved here, and the challenge for investors entering the market will be the changing dynamics; the model that has worked for several years will not necessarily be the model that works going forward. Up until now, the model has been predicated on relatively low costs with a relatively low margin for gas. We are now seeing an escalation in costs and change in dynamics in margins, so investors will have to assess exactly how they view the new model.

The contract structure that NGC shares with the upstream is a particularly unique one; what are your thoughts on this?

There are several considerations to take into account in examining our contract structure with NGC. BP sells approximately 60% of our gas to Atlantic LNG and the remainder to NGC through a series of complex contracts. Many of our older contracts with NGC were suitable at the time of signing but changing cost structures and commodity sales call for a re-examination of how they stand now. NGC operates as the middleman between the upstream and the downstream, so we need to consider what has changed in the markets to which the downstream sells. Our contract with Atlantic LNG is a different story; there are several contracts there that change from train to train, and as these come up for renewal in the next few years, we have to assess how we can make them the most beneficial for the country while ensuring that rents are distributed in the right way.