With the world economy once again on an upward trajectory, 2014 is likely to see a number of key oil and gas projects rise to the fore, whilst the E&P trend towards ever more challenging waters is anticipated to remain central to the leading operators’ investment strategies over the coming year. At the same time, however, significant challenges remain; uncertain energy prices are likely to be reinforced by the changing international tide towards Iran, while political unrest within North Africa is unlikely to abate in the near future. On a global level, the emergence of shale gas as an investment alternative will need to be accommodated by operators as part of development strategy, whilst the re-assessment of development budgets may also become an increasing sight as the industry moves into an ever more capital intensive stage of development - driven by the increasing prospectivity of fields within harsh environments, remote and deeper waters.
Altogether, Infield Systems expects 183 developments to enter production during 2014. A large number of shallow water, predominantly gas developments, are expected to be brought on-stream; driven by fields offshore Asia where Infield Systems forecasts a total of 27 gas developments to enter production during the year. Within the Middle East region the giant South Pars (Phases 13-14) and Qatar North Field dwarf all other developments, whilst offshore Europe, Infield Systems expects a total of 21 shallow water gas field developments to commence production.
Looking at those fields which predominantly hold oil reserves and beyond the giant shallow water development of Arkutun Dagi (Sakhalin 1), the trend towards deepwater development continues. Offshore Latin America and the Gulf of Mexico developments are also characterised by relatively short times between discovery and on-stream date – averaging around ten to eleven years. By comparison, in the European region, discovery to on-stream times average some 20 years, driven primarily by the growth of ‘marginal’ field developments offshore UK. Within the African region, the nature of development is far more varied. Tullow’s development of the Jubilee field offshore Ghana has been renowned for its record breaking discovery to production time of just 40 months, whilst Phase 2 of Jubilee (Hyedua) is anticipated to enter production during the course of 2014, taking just seven years from discovery to on-stream date. At the other end of the spectrum, Nigeria’s shallow water fields expected to enter production during 2014 average discovery to production times of 26 years, reflecting the challenging operating environment within the country and preference of IOCs towards deepwater field development.
In capital expenditure terms, shallow water developments are expected to form the largest share of global investment during the forthcoming year, with the North West European Continental Shelf (NWECS) and South East Asia anticipated to require particularly high levels of shallow water spend. Whilst developments in less than 500 metres are expected to hold the largest share of Capex, when looking at the top ten operators in isolation, 63% of expenditure for 2014 is expected to be attributable to deep and ultra-deepwater developments. Whilst NOC Petrobras leads deepwater development, a significant share of deepwater Capex spend is attributable to IOCs, reflecting the general split in the market, with Independents and most NOCs predominantly concentrating investments upon shallow water prospects. That said, leading Independent operators Anadarko and Noble are anticipated to continue their successful global deepwater campaigns during the year, with Anadarko expected to be the third largest deepwater spender within the GoM after LLOG and Shell, and Noble expected to continue its development of Tamar and neighbouring prospects within the Eastern Mediterranean.
On a regional level, Latin America is expected to continue to hold the largest share of total capital expenditure, with developments offshore Brazil expected to require 85% of regional Capex for 2014. Indeed, despite NOC Petrobras’ recent financial issue resulting in foreign divestments, the operator is pushing ahead with planned developments at home. Infield Systems expects the NOC’s capital expenditure to peak in 2014, driven by high profile projects such as Iracema Sul and Phase 2 of the giant Franco development. Within Mexico’s offshore sector, the long awaited PEMEX reforms, which will potentially open up the industry to foreign investment, appear ever closer. Certainly, with Infield Systems recording a total of 46 field prospects with potential for development before the end of the decade, the Mexican offshore industry is now facing a crucial time which could see the country restoring its dwindling production levels; whilst the forthcoming year is expected to see offshore investment focused upon the Sinan, Tsimin and Ayatsil fields in particular. Elsewhere within Latin America, Infield Systems expects significant capital expenditure to be directed towards Venezuela, where the multi-phase Perla development remains on-track. Once completed, currently expected in 2015, Perla is forecast to deliver 1.2bn cubic feet of natural gas per day to the domestic market.
Infield Systems expects the Asian region to hold the second largest share of global capital expenditure during 2014, driven by developments offshore Malaysia, with Petronas’s Rotan and Kanowit FLNG projects leading expenditure. With construction of the Kanowit platform commencing during the summer of 2013 at DSME’s shipyard in Okpo, South Korea, the race to develop the world’s first operational FLNG unit is also now underway, with the operator aiming for a start-up date of 2015. Rotan is expected to enter production a year later, whilst Shell’s giant Prelude offshore Australia is unlikely to commence production before 2017. Offshore Indonesia, Infield Systems anticipates that NOC Pertamina will continue to hold the largest share of expenditure, with Chevron expected to be the most significant foreign operator in the country. The US IOC is expected to focus upon the Gendalo-Gehem project, which will see the re-tender of its floating platform units at the start of the year. Developments offshore India are expected to also require substantial Capex spend during the year, with ONGC expected to hold a 92% share of the country’s investment. China-destined capital expenditure is expected to predominantly focus upon shallow water developments during 2014, comprising 87% of total expenditure for the year; although Infield Systems also expects the global trend towards deeper waters to be reflected in China’s offshore development going forwards. The Liuhua project, at a water depth of 723m, is expected to come on-stream during 2015 and successful exploration campaigns within the deepwater areas within Bohai Bay are also expected to continue during 2014. Elsewhere, with offshore licensing commencing for 19 deepwater and 11 shallow water blocks offshore Myanmar during Q4 of 2013, the expansion of exploration and production into the frontier waters of Asia’s offshore zones is set to continue throughout 2014 and beyond.
Offshore Europe, capital expenditure during 2014 is expected to be driven by developments within the NWECS region. Offshore Norway Infield Systems expects high profile projects such as Aasta Hansteen, Martin Linge and Edvard Grieg to drive expenditure. The forthcoming year is also expected to see the region’s leading operator Statoil rise to the position of fourth highest spender globally, behind Total, Chevron and Petrobras. With increasing development costs however, the Norwegian NOC has announced that it intends to keep exploration spending at the already record 2013 levels. Offshore UK the challenging Total-operated fields of Franklin West (Phase 2), Laggan and Tormore are expected to enter production during 2014, whilst Statoil’s Mariner field is expected to demand the highest capital expenditure during the year. As one of the largest projects ever undertaken within the North Sea, Mariner saw government approval in the early months of 2013. Once on-stream, which Infield Systems currently expects for 2017, the development is expected to produce around 55,000 barrels of oil per day; equating to 5% of UK output. However, challenges remain within the NWECS, with both Statoil’s Bressay and the Chevron-operated Rosebank hitting industry headlines during the final months of 2013 as each operator reassesses project finances. Indeed, with energy price uncertainty expected to continue, such announcements may become more commonplace
over the year as economic viability of capital intensive projects comes under the spotlight.
Offshore Africa Angola is expected to lead capital expenditure demand during 2014. The West African nation is expected to see investment return to levels not seen since before the world economic downturn, with operators Eni, Total and ExxonMobil claiming the largest shares of Capex spend on key projects including Mafumeira Sul and Chissonga. Projects offshore Congo (Brazzaville) are also expected to require a substantial proportion of the region’s offshore investment during the year, with the giant Total-operated Moho Nord Marine anticipated to require the highest levels of investment, whilst the Lianzi field, operated by Chevron, saw several key contracts awarded during the course of 2013. However, a less than positive outlook is expected for Nigeria. Despite significant expenditure being directed towards projects such as Egina and Bonga Northwest, total forecast investment is far below the country’s potential. With IOCs reporting substantial revenue losses and the much delayed Petroleum Industry Bill (PIB) unlikely to be passed through government before the close of the year, future Nigerian Capex may reduce further as operators turn towards the more stable operating environments of its West African neighbours and East Africa’s emerging offshore sector. Indeed, offshore East Africa Infield Systems expects increasing activity over the next year, with several operators announcing increased exploration budgets. Although Infield Systems does not expect offshore production to take place until 2015 on Aminex’s Kiliwani North field, Tanzania, with Mozambique holding the potential to become the world’s third largest exporter of LNG after Qatar and Australia, capital expenditure on developments offshore East Africa is anticipated to increase substantially over the forthcoming five years. However, with shale gas exports expected to increase significantly over the same period, it is vital for operators looking to unlock this vast potential to bring on-stream projects to timescale.
Within the North American region Infield Systems expects the deepwater Gulf of Mexico (GoM) to continue to lead capital expenditure demand, with significant investment anticipated on Anadarko’s Heidelberg and the LLOG-operated Marmalard developments, whilst the twin of the Heidelberg spar, Lucius, is expected to enter production during 2014. As the largest spar development undertaken by Anadarko, Lucius is designed to process some 80,000 barrels of oil per day. In addition, the platform also holds gas processing capabilities, necessitated by ExxonMobil’s Hadrian South tie-back, which is also expected to come on-stream during the course of 2014. Whilst 88% of North America’s capital expenditure for 2014 is expected to be directed towards GoM projects, the single largest expenditure during the year within the region is anticipated to be demanded by the ExxonMobil-led Hebron development, offshore Newfoundland. Discovered in 1981, the economic viability of the giant heavy oil prospect has long been in the balance, and with ExxonMobil now estimating a price tag in the region of US$14bn, it will be crucial to maintain this budget in order to realise potential revenue gains going forwards.
In terms of capital expenditure, the Middle East region is expected to account for a relatively marginal 7% share of global demand. Abu Dhabi and Qatar are expected to lead capital expenditure demand during 2014, with key projects including the giant Qatar North (Barzan Gas Project) forecast to enter production during the first half of the year. Once the two trains of Barzan Gas are brought on-line the entire development is expected to supply approximately 1.4 billion standard cubic feet of gas per day (Bscfd), making RasGas one of the largest single gas processors in the world. Projects within the Caspian Sea are forecast to also hold a significant share of 2014 investment within the Middle East, with Azerbaijan Capex demand surpassing that of Saudi Arabia. At the time of writing, the BP-led Shah Deniz II is expected to reach its final investment decision before the end of December 2013. Due on-stream in 2018, 2013 saw the TAP pipeline winning the contract to transport Shah Deniz output through the Southern Gas Corridor, thus providing 10 billion cubic metres of gas per annum to the European market. Elsewhere in the region, the giant South Pars (Phases 13 and 14) is expected to come on-stream during 2014, with Iran hoping to commence gas exports to Iraq by the middle of the year. With international relations appearing to soften towards Iran in recent months, the prospectivity of Iranian fields may also increase going forwards.
Whilst Australasia is only expected to hold 5% of total global capital expenditure demand for 2014, the North Western Australian market is fast developing into a hub for future LNG production, with the giant Prelude FLNG hull floating out of Samsung Heavy Industries yard at the end of 2013 and the ExxonMobil - BHP Billiton Scarborough FLNG gaining environmental approval a month earlier. During 2014, the Inpex-operated Ichthys LNG development is expected to demand some of the highest investment levels of any project globally, whilst Chevron’s Wheatstone LNG project is also forecast to require substantial expenditure during the year. However, whilst recent years have seen Australia’s LNG market touted as a prospective rival of Qatar’s leading position within the sector, escalating costs and the emergence of shale gas may act to challenge this potential.
Indeed, the global offshore industry certainly has some significant challenges to face going forwards. Whilst investment once again looks strong, and a number of industry firsts are nearing fruition, operators and contractors are simultaneously facing rising costs and technical challenges brought about by the steady movement into more challenging environments and the development of new production systems. Furthermore, with a number of capital intensive projects in the planning phases, the energy price movements of 2014, affecting the overall economic viability of future developments, will undoubtedly play the most pivotal role in deciding future offshore development.