Friday, 22 May 2015

What's the marginal cost of oil supply - $60/bbl or $80/bbl?

By Kim Fustier

Much has been written lately about the falling marginal cost of crude supply, as breakeven costs for US shale continue to fall. Last week, Goldman Sachs cut its Brent oil price forecast to $65/bbl in 2016-18 and to just $55/bbl in 2020, well below consensus and the long-term forward curve. The bank argues that US shale breakeven costs have dropped by $20/bbl in a year thanks to structural efficiencies and productivity improvements. The global oil curve has become flatter and lower, and growth from US shale and OPEC is enough to meet demand growth to 2025, the bank argues. 

Exhibit 1: Oil cost curve has shifted lower and flatter due to US shale
 Exhibit 2: Breakevens of non-producing and recently on-stream oil assets
Source: Goldman Sachs Investment Research

We have a lot of sympathy for GS's argument that US shale has fundamentally reshaped the global oil cost curve. It is now widely accepted that US light tight oil economics are generally more robust than many other sources of non-OPEC incremental supply, notably (ultra) deepwater and oil sands. Deepwater and oil sands have thus been duly pushed to the right of the cost curve and a myriad of deepwater and oil sands projects have been delayed.

Exhibit 3: Estimates of long-term breakeven costs for various project types
Source: Estimates of long-term breakeven costs for various project types

Shale breakevens in the top basins (Bakken, Eagle Ford and Permian) are well below the $80-100/bbl often required on deepwater, oil sands or enhanced recovery projects. To quote a few examples, Bakken producer Continental Resources expects average IRRs of 40% at $60/bbl assuming a 15% reduction in costs. If we assume a more reasonable minimum target return of 20%, Continental's oil price breakevens range from $50-60/bbl in the Bakken down to $30-40/bbl in the more profitable SCOOP (Oklahoma Woodford) shale. (These are quoted in local oil prices, which trade at a discount to Brent). Permian producer Concho Resources sees 50-60% IRRs at $60/bbl in the Permian basin with enhanced completions, implying low breakevens well below $50/bbl for a target 20% IRR. 

Exhibit 4: Continental Resources’ view on rates of return in the Bakken and SCOOP at various oil prices
Source: Continental Resources (April 2015). Note: CWC is completed well costs.

One important caveat is that shale break-evens are highly variable by play and county. The chart below from Wood MacKenzie shows significant variability in liquids-rich shale breakevens, ranging from $30/bbl to $130/bbl in the Eagle Ford. North Dakota’s Department of Mineral Resources  estimates break-evens in core Bakken counties at just $29-41/bbl, compared to $44-75/bbl in non-core areas. 

Exhibit 5: Shale break-evens show wide variations by play, sub-play and county
Source: Wood Mackenzie (March 2015). Note: Break-evens calculated as oil price required for a 10% IRR

Meanwhile, typical deepwater projects (if there is such a thing as a “typical” deepwater project) such as those in the US Gulf of Mexico or West Africa require around $80-90/bbl in a 2014 cost environment, and costs aren't coming down particularly fast. Lower service costs and smart re-engineering in the pre-FID phase could theoretically decrease these break-evens by, say, $10-15/bbl to a more palatable range of $65-80/bbl. Majors have asked for significant price reductions (20-30%) from their suppliers; but while drilling day-rates and seismic costs have fallen substantially (35-50%), subsea and platform construction costs have yet to come down materially. One exception is the Brazil pre-salt, with all-in supply costs of $40-45/bbl according to Petrobras, although this guidance is before cost overruns and delays.

If low-cost shale and OPEC can indeed meet all of the world's needs - and this is a big if, it begs the question of whether the world still needs expensive projects. 

In a world with no natural depletion and no demand growth, expensive projects such as oil sands and ultra-deepwater should simply not be needed, and the shale revolution would push down the long-term oil price to the $55-65/bbl level that GS has talked about. 

However, the reality is that the industry needs to put onstream c 4mb/d of new production just to stand still given natural decline rates and c 1.1mmb/d of annual world demand growth. We are doubtful that OPEC and even a buoyant US shale industry can together produce 4mb/d of liquids growth per annum. 

Exhibit 6: Global liquids supply & demand – each year, new fields need to offset decline and rising demand
Source: Chevron (March 2015), from IEA World Energy Outlook 

The charts below illustrate the enormity of the task at hand for the global oil industry. More than half the world’s oil is produced from fields already in decline, where underlying decline rates are typically 10-15% (ex-reinvestment) and probably closer to 4-6% post-reinvestment. 

As Exhibits 7-8 shows, most of the non-OPEC world’s mature or “legacy” production in terms of size is in Russia, China, Mexico, Brazil, Canada, the North Sea and central Asia, where decline rates range from 6% for the big onshore producing countries up to 15% at the top end for offshore and deepwater.

Exhibit 7: Declining production capacity by country in mb/d (2014 estimates) – more than half the world’s oil is produced from fields already in decline
Source:  Credit Suisse estimates, based on Wood Mackenzie (January 2015)

Exhibit 8: Underlying decline rates of producing fields are typically 10-15%
Source: Credit Suisse estimates, based on Wood Mackenzie (November 2014)

In conclusion, North American shale alone is unlikely to have shifted the entire global cost curve much below $80/bbl in the long run. Time will tell whether Goldman - which famously called for $200/bbl oil in the 1H 2008 bull run - or us will be proven right. 

Tuesday, 19 May 2015

Senegal appraisal looks to de-risk 2014 discovery success

By Elaine Reynolds

Cairn's Capital Markets Day this month focused on Senegal, providing some insight into its 2014 back to back independent discovery wells, FAN-1 and SNE-1. Here we look at the shelf edge discovery SNE-1 and point to the key uncertainties the company will need to address when it returns to drilling in the region at the end of 2015.

Exhibit 1: Senegal location map
Source: Cairn Energy

Exhibit 2: Senegal basin cross-section
Source: Cairn Energy

Cairn was very enthusiastic about its SNE-1 discovery when it reported initial results back in November 2014, so it is no surprise that it is focusing on appraising here now. The discovery well was drilled on the shelf edge in 1,100m of water and encountered 32° API oil in 30m of net oil bearing reservoir in a gross reservoir interval of around 100m in the target Albian sandstone. Data recovered from the well is very positive. Reservoir quality was described as excellent at the time of discovery and we now know that the average hydrocarbon saturation is over 70% and average porosity is 24%. while pressure measurements and fluid samples collected as part of the logging programme show good mobility from all the reservoir intervals.  

To follow up on these promising results, Cairn will return in Q4 2015 with a firm three well campaign consisting of two SEN appraisal wells and and exploration well on a shelf edge prospect. 

Cairn estimates unrisked 2C resources of 330mmbbls with a 1C to 3C range of 150 - 670mmbbls. A key risk on volumetrics  is commonly driven by uncertainty in OWC. Pressure data from the well has however provided a textbook pressure profile with clearly defined Gas Oil Contact (GOC) and Oil Water Contact (OWC) so that volumetric uncertainty comes from elsewhere in this case. The answer lies in the complex geology that overlies the 60 -100km2 field and complicates the seismic time to depth conversion, giving varied results. Getting to grips with this will be key, so drilling the two appraisal wells planned for SNE should allow de-risking by providing extra data points for seismic calibration.

In addition to reducing the resource uncertainty range, the appraisal programme will focus on establishing the reservoir continuity and connectivity. Nothing from the seismic suggests this will be an issue, but understanding this will be crucial to determining field commerciality. In SNE the plan is to assess this through interference testing sometime in 2016. Requiring a minimum of two wells, this involves monitoring a pressure response in one well to a transient change in another. 

Finally, the sand distribution in the reservoir will be something to pay attention to in the appraisal wells. Within the 30m of net pay found in SNE-1, we know that this is not one thick sand, but made up of a number of sands of varying thicknesses, from the order of tens of metres down to less than a metre. Thinner sands could prove more challenging to produce and effectively drain, so the prevalence of these will likely impact recovery from the reservoir.

Thursday, 7 May 2015

Saudi-led market share war with US producers continues

By Kim Fustier

In a recent blog post, we focused on US shale production dynamics, and highlighted the impact of continued rig productivity improvements on US shale production. 

Here we look at OPEC's strategy and risks of potential disruptions in OPEC and non-OECD countries, which could well have a larger impact on global crude supply than US shale.

For all the talk about the erosion of OPEC’s market share by growing US shale, the 12 member countries still represent over 39% of global supply (including NGLs), down only marginally from a 42% peak in the last decade.

Many market participants and commentators were caught flat-footed when Saudi Arabia decided not to cut production in November, at a time when something like 1mmb/d of capacity needed to be removed. The oil market’s 'central banker' thus sent a clear message to the oil market, which can be summed up as “go balance yourself”. Saudi Arabia's oil minister Al Naimi explained in a December 2014 interview that it was logical for the most efficient producers including Saudi Arabia and Iraq to protect or gain market share against less efficient oil producers, singling out Russia, Brazil and US shale. 

The prevailing view is that the odds of production cuts target at the next OPEC meeting, scheduled for 5 June 2015, are very low. OPEC is producing 31mmb/d as of March, compared to its theoretical 30mmb/d supply target. 

This view is borne out by Saudi’s 400mb/d output hike since January 2015, while at the same time Libya and Iraq were also adding output. Financially, Saudi Arabia is unlikely to be in a hurry to cut production as it has amassed large government budget surpluses and just under $700bn of reserves in recent years, and has low sovereign debt. Its foreign reserves are eroding to the tune of c $10bn a month, which would leave the Saudis with at least 5 years' worth of reserves. The recent rise in prices appears to be irking Saudi Arabia, with OPEC's monthly editorial blaming the actions of "speculators" buying front-month crude and storing it. 

Other less fortunate OPEC producers, specifically those with high budget break-evens such as Iran or Venezuela (see Exhibit 1 below), may well try to persuade Saudi to reduce output, but have little or no leverage over the kingdom.

Exhibit 1: Fiscal break-even oil prices for key OPEC and MENA oil producers
Source: EIA, Bloomberg, Edison Investment Research. Note: Yemen and Oman are not OPEC members. Production data as of March 2015 

Over the medium term, Iraq looks set to dominate OPEC supply growth with an estimated +1.1mmb/d by 2020 from a 2014 base of 3.34mmb/d (see Exhibit 2). Needless to say, Iraq’s expected supply growth comes with elevated risks, including IS-linked violence, infrastructure constraints, relations between Baghdad, the Kurdistan Regional Government (KRG) and foreign companies, and contract terms. 

Exhibit 2: Iraq dominates near- and long-term OPEC supply growth
Source: IEA Medium-Term Oil Market Report (February 2015)

In the nearer term, OPEC and MENA supply is likely to continue to fluctuate mainly due to geopolitical factors, which are by and large unpredictable. Risks to supply are mainly to the downside, with the exception of Iran. 
  • Libya’s output has halved to c 0.5mb/d since its unexpected Q314 recovery due to militant attacks. Production remains at under a third of the pre-Arab Spring level of 1.6mmb/d and there is no sign of stabilisation in the country. 
  • In Iran, the market was quick to price in incremental exports following a possible nuclear deal by the 30 June deadline. Iran’s crude production (ex-NGLs) has flatlined at 2.8mmb/d since 2012, down from a pre-sanctions level of 3.7mmb/d. However, any ramp-up in exports will probably be gradual as sanctions are lifted step by step and fields returned to production after a lengthy shutdown, with little oil flowing until late 2015 or even H116. 
  • Other countries to watch include Yemen, where eight MENA countries including Saudi Arabia are militarily involved. An escalation in Yemen could affect the broader region as well as oil tanker traffic; and Nigeria where Niger Delta disruptions could rise again following presidential elections.