Crude drop may defer oil sands, GoM projects

OREANDA-NEWS. May 29, 2015.  More than a dozen large oil projects in North America are under the microscope, facing the possibility of multiyear delays or indefinite suspension as a steep fall in crude prices and a weak demand outlook make them uneconomic.

The fall in oil prices since the 2014 highs has thrown the economics of extracting crude from oil sands and deepwater US Gulf of Mexico projects — which involve large upfront costs — into disarray. Breakeven costs for oil sands projects can easily exceed \\$100/bl, while deepwater projects need about \\$80-\\$85/bl.

Extracting shale oil is expensive too, but shorter drill times and lower per well development costs gives producers more flexibility to quickly respond to price swings.

The majority of multibillion dollar projects facing delays are in Canada, namely the Alberta oil sands. Among the projects that have already been deferred are the later phases of Cenovus' Christina Lake project, jointly owned by ConocoPhillips. There are five phases that are producing and Cenovus expects Phase F to come on line in late 2016. But work on Phase G has been deferred, it said.

Similarly, Cenovus is also deferring all three phases of its Narrows Lake project that have a total gross capacity of 130,000 b/d.

"We plan to take advantage of the slower pace of development to look for opportunities to improve our design and execution strategy to achieve the lowest possible operating costs for this project," it said.

Canadian Natural Resources is deferring its \\$470mn Kirby North Phase 1 thermal in situ project. Other projects such as PetroChina's MacKay River Phase 2/3, MEG Energy's Christina Lake, with a targeted total capacity of 210,000 b/d, Phase 2 of Husky and BP's Sunrise, which is expected to eventually produce 200,000 b/d, and Suncor's 20,000 b/d MacKay River expansion face multiyear delays, according to consultancy Wood Mackenzie.

Oil sands mining operations seen as indefinitely suspended include Syncrude Stage 4 and Total's Joslyn mine. Statoil's Kai Kos Dehseh Corner and Suncor's Firebag Phase 5/6 projects are examples of suspended in-situ developments, Wood Mackenzie said.

In the US Gulf of Mexico, attention is now focused on whether Chevron will make a final investment decision on its Buckskin and Moccasin projects, and BP on its Mad Dog II project.

There is still a "reasonable chance" BP will decide on Mad Dog II before year's end, chief financial officer Brian Gilvary said in their first quarter earnings call, adding a fall in rig rates is making the project's economics stronger. Chevron expects a decision on the Buckskin and Moccasin fields, being developed jointly, next year. Anadarko's plan to do more appraisal work at its Shenandoah project before making a final investment decision points to the ability of US Gulf projects to withstand price swings because of low production costs.

For onshore US shale developments, the largest number of delays or deferments are likely in the Bakken area in North Dakota, which has seen the steepest fall in rig count compared with the other two key US shale oil producing areas: the Eagle Ford and Permian in Texas. The rig count in the Bakken has fallen by 57pc from the November 2014 peak while it has dropped by 53pc in the Eagle Ford and by 50pc in the Permian, according to Wood Mackenzie.

Whiting Petroleum, which became the top Bakken producer after acquiring Kodiak last year, has halved its 2015 capital expenditure (capex) in 2015 to \\$2bn. Another key producer, Continental Resources, has slashed its 2015 capital spending by nearly half to \\$2.7bn from a plan of \\$5.2bn announced in September. It expects output to grow by 16-20pc this year versus 28pc in 2014, by focusing on core areas.

Shale producers have across the board made hefty cuts in their capex, but the reduction for producers such as EOG Resources — whose operations are more focused on the Eagle Ford and Delaware basins in the Permian — is more tempered, by 40pc to \\$4.9bn-5.1bn.

The Bakken shale's longer distance to markets, compared with the Permian and Eagle Ford basins, have meant that its crude has often fetched a discount as deep as \\$20/bl to Nymex WTI prices.

Overall, a gradual recovery in prices will give shale producers enough room to add rigs and increase output, but a sudden price spike triggered by a geopolitical crisis may make US producers scramble to step up output to feel the supply gap and get higher returns.

"It is very difficult to quickly ramp up rig counts," research director for Lower 48 upstream at Wood Mackenzie RT Dukes said. "We have seen a fall in rig count of about 500 over three to six months, but it will take about two years to add the same number back."