Producers that in late 2014 began to carefully prune discretionary spending now are cutting all nonessential expenditures, which in 2015 upended at least 68 major oil and natural gas projects worldwide worth a total of $380 billion, Wood Mackenzie Ltd. said.
The delayed or scuttled projects hold an estimated 27 billion boe of commercial reserves, with deferred U.S. oil projects accounting for most of the losses, the consultant said Thursday. One-third of the total, 22, with an estimated 7 billion boe have been shelved since last summer, an updated analysis indicated.
Wood Mackenzie researchers in July had estimated 46 major global projects representing more than $200 billion in capital expenditures (capex) had been canceled or deferred (see Daily GPI, July 28, 2015).
Hit hardest is the deepwater, accounting for more than half of the total in lost projects, as companies are forced to rework the years' long projects that have high breakevens, large capital requirements and high costs.
"The impact of lower oil prices on company plans has been brutal," said Angus Rogers, principal analyst for upstream research. "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 nonessential operational and capital expenditure. Tumbling prices and reduced budgets have forced companies to review and delay final investment decisions (FID) on planned projects, to reconsider the most cost-effective path to commerciality and free-up the capital just to survive at low prices.
"For all 68 projects there are multiple elements contributing to delay," he said. "Price is rarely the only factor slowing down FID -- but it has exerted the strongest influence."
According to the update:
Delayed spend from the 68 projects shelved totals $170 billion between 2016 and 2020;
Deepwater deferrals have risen to 29 from 17 in July, representing 62% of total reserves and 56% of total capex;
2.9 million b/d of liquids production has been deferred to early next decade, up from 2 million b/d six months ago;
Oil is most impacted, with deferred liquid volumes up 44%, versus 24% for natural gas; and
Average breakeven of delayed greenfield projects is $62/boe.
"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," Rogers said.
The analysis showed that cost inflation is where deepwater has made the least gains, he noted. "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% despite the global crash in rig dayrates. 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."
Tom Ellacott, vice president of corporate analysis, pointed out that since Wood Mackenzie ran the previous analysis, a key change for companies is stricter investment criteria. "Companies are having to adjust investment strategies to the risk of sustained low prices and this means tougher screening criteria for pre-FID projects," he said. "We believe that most companies will now be looking for these developments to hit economic hurdle rates at around U$60/bbl.
"Tougher capital allocation criteria will give companies the framework to make difficult decisions about restructuring portfolios, optimizing pre-FID projects and capturing the full benefits of cost deflation. If a sector or country cannot meet new investment thresholds and compete for capital, operators are now more likely to choose divestment over warehousing a stranded resource."
The production impact of the deferments is material in a global context.
"By 2021, deferred volumes will reach 1.5 million b/d, rising sharply to 2.9 million b/d by 2025," Rogers said. Last month Tudor, Pickering, Holt & Co. estimated that projects shelved since 2014 could leave at least $125 billion a year on the table investment-wise over the next five years and endanger 125 billion boe-plus of reserves (see Shale Daily, Dec. 2, 2015).
Wood Mackenzie's findings concluded that FIDs on many of these projects have been pushed back to 2017 or beyond, with first production now targeted between 2020 and 2023. Against a backdrop of overwhelming corporate pressure to free-up capital and reduce future spend -- to the detriment of production growth -- a "considerable scope" exists for this wall of output to be pushed back further if prices do not recover or costs do not fall enough.
The United States has the largest inventory of delayed oil projects because it holds nearly 90% of the deferred liquids reserves in the onshore, oilsands and in shallow and deepwater. Also with a large inventory of shelved oil projects are Canada, Angola, Kazakhstan, Nigeria and Norway.
"Those with the largest gas reserves are Mozambique, Australia, Malaysia and Indonesia, which combined hold 85% of the total volume," Rogers said. "The majority of this gas is found offshore, primarily in deepwater locations, and requires complex and expensive development solutions" for greenfield and floating liquefied natural gas projects.
"With oil prices recently falling to their lowest level since 2004, oil and gas companies will be forced to go into survival mode in 2016," said Ellacott. "Further project delays and cuts to discretionary investment are highly likely. That said, companies are being forced to re-evaluate how they can profitably develop large, high-cost conventional resources at low prices.
"Not only are we seeing a genuine push toward standardization, but low prices will also promote a level of innovation so far only seen in U.S. tight oil. The pace of capex and operations expenditure deflation may therefore surprise on the upside in 2016. Finally, we expect oil prices to start recovering during the second half of the year, which should encourage first-movers to kick-start investment and lock-in gains from cost deflation ahead of the herd."