Briefing: Megaproject Deferrals Stack Up as Majors Await Cost Relief

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Major oil companies are putting off investment decisions on new megaprojects, and only a sustained recovery in oil prices or a sharp reduction in development costs are likely to prompt them to sanction more of these high-cost schemes in oil sands, deepwater, LNG and the Arctic. Unfortunately, neither appears likely to occur anytime soon, raising questions about the outlook for majors' production later this decade and into the next. The "Big Five" majors -- Exxon Mobil, Royal Dutch Shell, Chevron, Total and BP -- plan to reduce capital expenditure this year by 15% or about $25 billion, but their caution about today's lower prices extends well beyond 2015. These companies are already delaying final investment decisions (FIDs) or otherwise rethinking plans for more than 20 multibillion-dollar megaprojects (see table). While most attention is currently fixated on the response of the US shale oil producers to low prices due to the short-cycle nature of that business, the deferral of megaprojects could have significant supply implications for the medium and long term. "What concerns me more than shale is the production outlook four, five, six years down the road with the majors delaying all these projects," says Oppenheimer & Co. analyst Fadel Gheit. These deferrals, he adds, will affect majors' ability to replace reserves and grow production. To put it in perspective, Goldman Sachs has estimated that $930 billion of future investment is at risk from low prices, based on its analysis of the world's 400 biggest new oil and gas field developments, excluding shale. These early stage projects, which would be uneconomic at $70 per barrel Brent, represent some 2.3 million barrels per day of production by 2020 and 7.5 million b/d by 2025. Majors began postponing FIDs on megaprojects last year amid $100 oil due to escalating costs, which were wrecking financial returns (EIF Dec.10'14). The price collapse in the second half of 2014 and continued low prices this year have accelerated this rationalization process, as majors brace for a prolonged downturn and look to rebase their costs to cope with lower oil prices. By delaying FIDs, majors are giving themselves time to bring down contracting costs in the hope of making megaprojects profitable at lower oil prices. But costs for large, complex projects such as oil sands, LNG, the deepwater and the Arctic -- the focus of the majors' deferrals -- don't respond as quickly as those with short investment cycles like US shale. That means projects could be shelved for longer than expected if the majors stick to their promises to significantly reduce break-even costs by imposing greater capital discipline. Total shocked investors last year when it conceded that its break-even costs were $100/bbl. As the French major strives to bring that figure down, it will take no major FIDs this year. BP is trying to reduce its cost base in line with a $50-$60/bbl Brent price, but its upstream strategy is heavily dependent on the deepwater, so it is waiting for a substantial fall in offshore costs before moving ahead with projects like Mad Dog II in the Gulf of Mexico. While the market for deepwater rigs and seismic vessels is down by 40%-50%, there has yet to be a significant fall in subsea or platform construction costs, Total Chief Financial Officer Patrick de la Chevardiere says. "My view is that the backlog of those [services] is strong enough that [the contractors] can wait for what they think will be a higher oil price -- and we are waiting for them to reduce their quotation," he says. UBS analyst Angie Sedita says the dayrate of the deepwater rig is not the issue, but rather the incredibly high development costs. Development costs in 8,000 feet of water are running as high as $20 billion to develop one field. "Offshore rigs could be offered for free and most oil companies would still not want to drill. The risks are high and due to inefficient and over-engineered processes to develop deepwater fields, still too costly. Deepwater returns for the large IOCs [international oil companies] have been abysmal, in many cases," Sedita states. Shell has deferred FIDs on three deepwater projects -- two in the Gulf of Mexico, one in Brazil (Libra) and one in Nigeria (Bonga Southwest) -- to 2016 in hopes of driving contractor costs lower. It will likely make a decision on a fourth -- Appomattox in the US Gulf -- by the end of 2015, but only because if it doesn't, it risks losing the license. Besides negotiating with their service contractors, majors will also work other channels to reduce costs. History shows that low oil prices don't necessarily bring about revised contractual terms with host governments that favor producers, but there may be room for majors to seek cost relief in areas like state-mandated use of local content (EIF Jan.28'15). Pushing back on local content requirements was one way Total was able to shave $4 billion off its $16 billion Kaombo project offshore Angola, allowing it to sanction that deepwater project last year (EIF Feb.25'15). Local content is a "journey" that is "flexible," the head of state Ghana National Petroleum Corp., Alex Mould, told the IHS CeraWeek conference last month. But he stressed that the producer-government relationship should be "symmetrical," so that "when oil prices go up, both parties benefit, [and] when they go down, both can revisit." Redefining the host government-producer relationship will take time to work out and provides little near-term solace for majors. Patience and prudence is their message to investors. Chevron, for instance, has said explicitly that it will never take on a slate of megaprojects as big as the one it currently has. When it starts to sanction projects again, Chevron vows to manage fewer concurrently so it can devote more attention to costs and schedules and execute them better. Majors' upstream production was flatlining or shrinking even before the oil price collapse, raising questions about how their portfolios would respond under lower capex programs. The group is largely holding to previous production guidance for the next couple years, but beyond that it's unclear how deeply recent project deferrals will cut. Although Exxon expects to invest around $34 billion annually in 2015-17, compared with previous projections of $37 billion annually, it has maintained its growth guidance of 4.3 million barrels of oil equivalent per day in 2017, up from 4 million boe/d in 2014. While Exxon hasn't publicly deferred any projects, Chief Executive Rex Tillerson acknowledges it is "only going to take on what we know the market is ready for," and analysts note a high number of oil sands and LNG projects in its post-2018 portfolio. Shell will spend $15 billion less over the next three years, resulting in the cancellation or deferral of 40 projects worldwide, excluding assets added via its BG takeover -- a deal that confirmed its long-term commitment to deepwater and LNG (EIF Apr.15'15). But it is still looking at 17 potential FIDs in 2015-16 that it believes could add more than 700,000 boe/d in new production and some 12 million tons per year of LNG capacity. Cost and Price-Related Deferrals of Major Projects 2014-15 Company Project Action Cost* BG Prince Rupert LNG, Canada FID deferred $16 billion BP Mad Dog II (US Gulf) FID deferred $14 billion BP Liberty, US (Alaska) FID deferred NA BP Tangguh LNG Train 3, Indonesia FID deferred to 2016 NA Chevron Rosebank, UK North Sea FID deferred $10 billion Chevron Gorgon Train 4, Australia FID deferred NA Chevron Tengiz expansion, Kazakhstan FID deferred to late 2015 NA Chevron Wafra, Neutral Zone FID deferred NA Chevron Kitimat LNG, Canada FID deferred $28 billion Chevron IDD Phase 2, Indonesia FID deferred $12 billion Shell Bonga Southwest, Nigeria FID deferred to 2016 $12 billion Shell/Inpex Abadi LNG, Indonesia Re-phased; delayed three years to 2024 NA Shell Carmon Creek 3 & 4, Canada Re-phased; delayed two years to 2019 NA Shell Pierre River, Canada Deferred NA Shell Arrow LNG, Australia Canceled NA Shell/Woodside Browse LNG, Australia FID deferred NA Shell Appomattox, US Gulf FID deferred to late 2015 NA Shell Vito, US Gulf FID deferred to 2016 NA Shell/Total Libra, Brazil FID deferred to 2016 $80 billion Statoil Johan Castberg, Norway FID deferred to 2017 $13.5 billion Statoil Snorre 2040, Norway FID deferred $5.7 billion Statoil Corner, Canada FID deferred NA Suncor White Rose Extension, Canada FID deferred NA Suncor Corner, Canada FID deferred NA Total Zinia 2, Angola FID deferred NA *Most recent estimate from operator or consortium member

Exploration, Offshore Oil and Gas, Shale
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