• Thursday, July 25, 2024
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Upstream projects deferred in Nigeria, Angola, others as low crude price persists

Oil production platform and supoort ships Alaska

Many upstream projects across the world have been deferred as low crude oil price persists. According to a report by Wood Mackenzie, the countries with the largest inventory of delayed oil projects are Nigeria, Angola, Canada, Kazakhstan, Norway and the US.

Wood Mackenzie provided an update on the impact of continued low oil prices on upstream oil and gas projects. The updated report concluded that in the last six months of 2015 an additional 22 major projects and seven billion barrels of oil equivalent (boe) of commercial reserves have been deferred, on top of the 46 developments and 20 billion boe of reserves identified previously. Deepwater projects have been hit hardest, accounting for over half of the total, as companies are forced to rework projects with high breakevens, large capital requirements and high costs.

The report reveals that $380 billion of total project CAPEX deferred (real terms), from the 68 projects; of the $380 billion CAPEX, delayed spend from the 68 projects from 2016 to 2020 totals $170 billion. Deepwater is the hardest hit with more than half of new project deferrals up from 17 to 29; 62 percent of total reserves; and 56 percent of total CAPEX. 2.9 million barrels a day (b/d) of liquids production deferred to early next decade, up from 2 million b/d.  From the deferred projects, oil is mostly impacted at up 44 percent deferred liquid volumes versus 24 percent for gas with a projection of an average breakeven of delayed greenfield projects is $62/boe.

The deferred projects includes oil sands, onshore, shallow-water and deepwater assets in both greenfield and incremental developments. Those with the largest gas reserves are Mozambique, Australia, Malaysia and Indonesia, which combined hold 85 percent of the total volume. The majority of this gas is found offshore, primarily in deepwater locations, and requires complex and expensive development solutions, including greenfield LNG and FLNG.

Angus Rodger, principal analyst, Upstream Research for Wood Mackenzie, explains that “the impact of lower oil prices on company plans has been brutal. What began in late-2014 as a haircut to discretionary spend on exploration and pre-development projects has become a full surgical operation to cut out all non-essential operational and capital expenditure. Tumbling prices and reduced budgets have forced companies to review and delay Final Investment Decisions (FID) on planned projects, to re-consider the most cost-effective path to commerciality and free-up the capital just to survive at low prices.”

Wood Mackenzie’s report “Pre-FID project deferral update: deepwater hit hardest” has identified 68 large projects globally that have had FID delayed due to the fall in oil prices since the oil price crash in 2014 to the end of 2015. The list has grown by over a third in the last six months, as more and more projects are deferred through the down-cycle. Rodger adds: “For all 68 projects there are multiple elements contributing to delay. Price is rarely the only factor slowing down FID – but it has exerted the strongest influence.”

“One reason we are seeing a growing list of delayed projects is cost deflation – or to be more accurate the need for costs to fall more to stimulate investment,” Rodger adds. And the analysis shows that this is where deepwater has made the least gains: “The biggest jump in pre-FID delayed projects over the last six months was in the deepwater, rising from 17 to 29, where costs have only fallen by around 10 percent despite the global crash in rig day-rates. Despite the size of these fields, the combination of insufficient cost deflation and significant upfront capital spend has discouraged companies from greenfield investment in the sector.”

The report’s findings conclude that FIDs on many of these projects have been pushed back to 2017 or beyond, with first production currently targeted between 2020 and 2023. But against a backdrop of overwhelming corporate pressure to free-up capital and reduce future spend, to the detriment of production growth, there is considerable scope for this wall of output to get pushed back further if prices do not recover and/or costs do not fall enough.

$20 per barrel, no longer mirage

11 months ago when Citigroup report said oil could drop as low as $20 per barrel, nobody paid attention. Analysts believe it is no longer a mirage now that crude has tipped below $30.

BP Plc slashed 4,000 jobs, Petrobras slashed its spending plan and Petronas warned that it faces several tough years before crude futures in the US sank into the $20s for the first time in more than 12 years.

Low oil prices could cause problems for both countries and oil companies. Malaysia stands to lose $68 million for every $1-a-barrel decline in crude, according to government estimates. ConocoPhillips is losing $1.79 billion in net income each quarter for every $10 drop in prices, according to analysts at Barclays Plc. Petrobras, as Brazil’s state-controlled oil producer is familiarly known, cut its five-year business plan to $98.4 billion, the latest adjustment to the original $130 billion announced last year.

The US Energy Information Administration reduced its forecast for WTI prices for 2016 by 24 percent to $38.54 a barrel. In its monthly Short-Term Energy Outlook, the agency said the oil market would come back into balance in 2017.

The call for oil in the $20s grew louder in recent months, with Goldman Sachs pinning a 50 percent chance of oil falling to $20 in September and Morgan Stanley saying recently that a strong dollar could drop oil below $30.