Interview: Norman Christie
What savings can be made by the local energy industry during a period of low oil and gas prices?
NORMAN CHRISTIE: The industry has a lot of work to do in terms of improving costs in areas such as logistics, improving the ease of doing business and fixing inefficient economic incentives. In the latter respect, the distribution of margins across the gas value chain is inefficient, because of the way the industry has historically developed. In the 1980s and 1990s, it was clear that the upstream enjoyed relatively low risk and that the real policy challenge was to incentivise investment in downstream plants. As a consequence, the relatively higher risk profile borne by midstream and downstream players was rewarded with a higher return than that given to upstream players. The risk profile has changed and the cost that upstream players have to bear is higher. These built-in inefficiencies have contributed to the recent years’ disruptions in gas supply.
The Natural Gas Master Plan 2014-24 announced by the Ministry of Energy and Energy Affairs is expected to influence this issue through policy. Addressing it now is critical, as three major contracts are to be renegotiated soon. These are the Atlantic Train 1 contract; the National Gas Company (NGC)-BPTT contract – the largest domestic gas contract; and the NGC-BG Group Trinidad and Tobago contract. The first two will expire in 2018, but the third contract expires in 2015. The right policy framework must be in place to re-negotiate the contracts, and conditions to set the price for new downstream developments must also be there.
In light of US shale gas development, can the downstream industry remain competitive if margins are redistributed along the value-chain?
CHRISTIE: I believe so. From a cost of supply perspective, T&T still competes with US shale gas in certain regards. Despite the shale gas revolution, the cost of establishing a new plant in the US may still be higher than in T&T. I believe that somewhere within the T&T gas value chain, there is an opportunity to split the economic pie in a way that works well for all parties. The cost of gas supply could be raised for midstream and downstream players to a level where they remain competitive relative to a US producer of the same product, while allowing upstream suppliers to achieve the returns necessary to invest in capital projects. It is a balancing act to remain competitive as an industry relative to other countries. There are also some built-in inefficiencies at some plants that could be corrected.
How have the improved fiscal terms changed the economics of new capital investments?
CHRISTIE: The tax environment has been made more competitive over the past few years, especially for deepwater exploration. BP was the first to be awarded a deepwater production-sharing contract. This would not have been feasible without changes in the fiscal structure. Further improvements such as the accelerated depreciation provisions under exploration and production licences, have benefitted projects such as Juniper, which required the changes in order to be sanctioned.
How much will BPTT’s overall gas production levels change when the Juniper project comes on-stream?
CHRISTIE: BPTT operates with three primary offshore hubs – Cassia, Mahogany, Amherstia – and satellite fields. The challenge we face is keeping them as near as possible to full capacity. When a new field comes on-line, in most cases it is replacing another field’s place in the hub. For instance, when Juniper comes onstream, the Savonette field will be declining.
As mentioned earlier we have been experiencing relatively curtailed production over the last few years, but with Juniper coming on-line we will see some increase in production, even if not to the levels seen five years ago. In the past, BPTT could ensure some cushion gas production to cover excess demand. Even with the start of Juniper in 2017, however, it is unlikely that we will achieve historical levels of cushion gas unless there is some fundamental change in commercial structures.
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