OSLO, Norway – Schedule slippage is an ever-present reality for E&P projects, especially for the more complex mega-projects. In addition to subsurface challenges, above-ground issues, such as government red tape or delays in reaching binding sales agreements, can derail planned sanction schedules.
On top of this, the drastic drop in revenues due to the oil price decline has imposed stricter financial prudence on E&P companies, according to Readul Islam (Tipu), senior analyst for Rystad Energy, in a recent update. Risky exploration spending has been called off; incremental developments such as infill drilling at already producing projects have faced higher hurdles for approval. However, post-appraisal pre-sanctioned projects have borne the brunt of the prudence.
Rystad Energy has been tracking delays announced (or inferred) since 2H 2014 for pre-development projects, where sanctioning could have reasonably been expected within two years of the delay. Compared to its mid-2015 update, the delayed projects count has increased from 40 to 63. Much of this increase has come from delays to smaller, less complex projects, often operated by smaller companies. Thus, even though the delay count has risen by 58%, total resources and capex delayed figures rose by 30% and 38%, respectively.
The first casualties as oil prices declined were the more complex and costlier oil sands, LNG and deepwater projects. But as the oil price continued its slide during 2H 2015, E&P companies cut costs by deferring the smaller, simpler projects in their portfolios. Petronas delayed the tender submission date for its Kasawari gas development offshore Malaysia’s Sarawak province. Woodside deferred Cossack North offshore Australia after a portfolio review of spending. Operator Chevron’s partner PTTEP at the Ubon project offshore Thailand signaled a development reassessment.
According to the report, the mid-2015 delay list mainly featured the majors, international NOCs and the larger independents. But by 2H 2015, the downward price spiral snagged smaller operators, with Vioco Petroleum recommending the deferral of the shallow-water Gazelle development to the Ivorian authorities. Sunbird Energy’s plans to supply a South African utility with offshore gas from Ibhubesi ran into trouble due to the critical financial status of both the seller and the buyer.
The report noted that uncertainty in the Indian long-term gas price outlook claimed Reliance’s deepwater D-34 development. Chevron will reportedly be re-tendering IDD2 contracts — uncertainty over an extension of the contracts for the blocks containing the Gendalo-Gehem fields does not help the plans for Indonesia’s first deepwater development.
Rystad Energy estimates the deferral of these 63 projects will result in more than 3 MMboe/d (60% crude and condensate) of supply delayed at a peak production that is expected in 2026. Nigeria, Kazakhstan, and Indonesia are the main countries affected, followed by Norway and Canada.
However, the spending delay precedes the supply delay. With these projects expected to be on track to sanction within two years of the delay detection, oil field service (OFS) companies likely had these projects on their planning horizons. According to the report, the deferred $230 billion would originally have been expected to be largely spent during 2015-20, with OFS companies chasing the development contracts for these projects.
In order to stay competitive in a buyer’s market for their services, OFS companies have been compelled to reduce service rates. And E&P players with projects due for imminent sanction could return to the drawing board. With no incentive to increase supply with oil prices expected to stay lower for even longer, the lure of lower costs from even tighter OFS cost compression could prove irresistible.