Thursday, 9 June 2016

Oil and Gas Macro Outlook - Tightening market buffered by abundant inventories

Summary

Oil price volatility remains high with Brent crude having risen 17$/bbl or 51% since our latest published macro outlook in January 2016. Since then we have seen supply impacted by a 1.2mmbpd reduction in Canadian output due to wildfires, combined with underinvestment and instability- driven supply interruptions across OPEC members:  Venezuela, Libya and Nigeria. Some of these temporary supply impacts will reverse over the coming months; nonetheless, we expect the oil market to tighten over the course of 2016. Although record levels of inventory and uncertainty over the sustainability of emerging market demand growth may limit near term price gains,  longer term, we expect prices to rise to c.70$/bbl in-line with levels required to incentivise non-OPEC supply expansion. Our short term oil price assumptions remain aligned to EIA STEO forecasts at 43$/bbl Brent in 2016 and 52$/bbl in 2017.
Rebalance underway
IEA short-term supply / demand forecasts point towards a market re-balancing over the course of 2016, with the agency’s base case forecasts suggesting just 0.18mmbpd of oversupply in Q416. Stress testing key assumptions including LTO (light tight oil, or US Shale) output, Iranian volumes and emerging market growth suggests that under all scenarios we should see a tighter market in 2H16 than in the first half of the year. The precise timing of the inflexion point at which we start to see sustained inventory draw-down is uncertain, and a slow-down in emerging market growth rates could push this tipping point well in to 2017.  

Short term uncertainty remains  
Given the volatility in the oil markets and considerable uncertainty to macroeconomic trends, we feel it prudent to align our short-term assumptions with that of the global agencies. We maintain our assumptions aligned to the latest EIA forecasts for Brent of $43/bbl in 2016 (from $40/bbl) and $52/bbl in 2017 (from $50/bbl). Implied volatility of future contracts remains exceptionally high with the December 2016 WTI contract implying a 95% confidence interval of 26.5$/bbl to 83$/bbl and 68% confidence interval of 35$/bbl to 63$/bbl.

Long-term assumption unchanged at 70$/bbl
Break-even prices for marginal producers continue to fall after a c.15-25% reduction in 2015. Edison research indicates offshore projects can already be executed for full-field costs 20% below the levels of 2014, with further cost deflation expected in 2H16. Against this backdrop, we expect there will be a structural shift in the market to lower break-even prices in the short-term; however, cost-curves remain dynamic and we should start to see a shift back upwards if oil prices rise substantially, albeit with a lag. Assuming OPEC remains an observer rather than a price-setter, our approach remains to set our long-term oil price assumption around the economic return for marginal developments on the global supply curve; we maintain our long-term Brent assumption at $70/bbl.

A tightening market buffered by abundant inventories
A Saudi-led OPEC market-share protectionist policy has driven a marked increase in inventories over 2015, providing a buffer against short-term supply shocks. A 1.2mmbpd reduction in Canadian output, during the latter part of May 2016, would have historically sent oil prices skyrocketing, but with OECD crude inventories 360mmbbls above their five year average, short-term supply-shocks are currently little cause for concern. Of greater significance are the longer-lasting impacts of underinvestment and instability across OPEC: Nigeria, Libya and Venezuela in particular. To date a combined 450kbod y/y decline in production amongst this group of three has played a significant role in offsetting the post-sanction increase in Iranian output.  


Unplanned OPEC outages

Looking ahead to 2H16, uncertainty remains with regard to the timing of the inflexion point at which consumption exceeds supply. The IEA expects the market to trend towards balance by 4Q16, a sharper contraction in oversupply than forecast in January 2016. Un-anticipated supply disruptions appear to be the key delta. Other than unplanned supply disruption, key areas of uncertainty within the agency’s current supply / demand forecasts include:
1)  Supply: US LTO production response
2)  Supply: Recovery in post-sanction Iranian volumes
3)  Demand: Chinese demand and the impact of recent monetary policy
4)  Demand: The sustainability of Indian demand growth
Flexing US LTO production and Iranian volumes by +/-200kbd from IEA base case forecasts and Chinese / Indian annual demand growth by +/- 1% we see a wide-range in potential implied crude stock change outcomes over the remainder of 2016 (exhibit 4) . Despite uncertainty, all scenarios suggest that the market is set to tighten over the remainder of 2016 which we believe will provide price support.



IEA base case implied stock change and 2016 implied stock change sensitivities



 

Amongst the uncertainties, US LTO production in particular has proven to be exceptionally hard for analysts to forecast, this is despite leading indicators such as the Baker Hughes rig count. LTO production dynamics remain complex and are driven by numerous factors including well productivity, decline rates, wells drilled but un-completed, operator cash constraints and pace of service sector cost deflation. Investors should play close attention to the monthly EIA drilling productivity report in order to track the course of US LTO production over the course of 2016.

Longer term either input prices have to shift down or oil prices up
In the long term, we expect global inventory levels to normalise, and OPEC spare capacity to remain below 3mmbpd (c.3% of demand), driving prices back up towards non-OPEC marginal cost. We maintain our long term oil price assumption at 70$/bbl Brent based on a normal return for a pre-FID project towards the top end of the cost curve. Estimates of the breakeven cost* for new developments have shifted over time, taking in to account new sources of supply (e.g. US LTO) combined with service sector cost deflation. The cost curve presented below uses a combination of company data on project breakevens and published cost curves from a range of industry sources. We have shifted our base case curve down to provide a broad-brush indication of the impact of further cost deflation over the course of 2016 assuming a further 5% reduction in breakeven for onshore projects, 10% for offshore and 15% for US LTO.
*defined as the price at which a development generates zero return NPV(10%)=0.



Global liquids cost curve yet to be developed discovered resource. FID due over the next 10 years




BP Stat review - quick thoughts and highlights

by: Will Forbes

The annual BP Statistical Review is the industry standard source for tracking energy trends, usage and  sources.  Full details of the Statistical Review can be found here. This year's edition was presented yesterday, with interesting commentary made on the statistics.

Headline trends for 2015 vs 2014
Oil demand grew 1.9%
Gas demand grew 1.7%
Renewable energy grew 15.2%
Coal energy use fell 1.8%

Past episodes of price falls
The current cycle is driven by additional supply, more simialr to the cycle in the mid-1980s than the last two (demand-driven) shocks. New production from the US shales will take time to be absorbed by the market. 




Key suppliers' reactions to oil price falls makes sense
2015 was a tough year for oil prices. BP talks about the reaction to the pricing movement. Unlike the last two price falls, which were driven by demand shocks, the supply-driven price fall in 2014/15 was countered by OPEC making "offsetting adjustments to help stabilise prices". Instead the members (most Saudi Arabia) instead sought to maximise market share at the cost of lower prices. This is well known and recognised in the market. 

Interestingly, BP's team also believe that Russia used the same strategy in its approach to European gas. Faced with increased competition from lower LNG prices, the data derived by the BP team suggests that it sought to retain market share by lowering prices more aggressively than a simple oil-price link would have suggested. Due to contractual sensitivities, this cannot be seen directly, but BP have derived a German delivered cost (see below) which fell more quickly than may have been suggested.




As the chief economist states "The important point here is that ceding market share in order to support prices is less attractive when the underlying cause of the imbalance is expected to persist, rather than be relatively short-lived"

Oil demand reaction to price fallsBP's data suggests a bifurcation in the markets. As prices fell, demand for consumer-focused fuels (gasoline and jet) grew strongly. More industrial-focused fuels (diesel) has been slower to react. 

Company reactions to price falls - On the supply side, US shale rig count fell precipitously as cashflows and financing dried up. Companies across the world have slashed capital investment budgets, delaying or cancelling projects. BP estimates 2015 capex has fallen by 25% from 2014 levels ($160bn) - the largest fall since the 1970s. Without a strong uptick in prices, we would expect a prolonged period of lower investment.

Lower absolute investment has been partially offset by falling service costs (BP indicate in the range of 20%), which means real investment has fallen less. This is an important point. As a quick and dirty analysis, the table below shows the effect of balancing investment and costs.



Of course, this doesn't show where costs and investment have been most affected (exploration/development, onshore/ offshore etc) or the exact effect on profitability of projects

Renewables
Renewable Energy grew strongly, with Wind power (17%,  125TWh), followed by solar (32.6%, 62TWh) driven by Chinese supply. Hydro and Nuclear grew more modestly.



Carbon emissions
The headline here was that BP estimate that "carbon emissions from energy use were essentially flat last year", in sharp contrast to the 10 year average of 1.5% growth. This was helped by China's emissions being flat to down (-0.1%) for the first time in 20 years. This is caused both by cyclical weakness and the gradual rebalancing of the economy from heavy industry, reducing Chinese energy intensity.

Future trends
Huge amounts of attention have been given over to required improvements in the energy mix to get to a lower carbon future. Within this discussion, the growth of renewables is of particular interest. BP assumes that they grow at 8% pa, a much faster rate than previous new sources of energy have done. For example, BP look at the point that energy sources reach 1% of demand as the starting point - in this case it took 40 years for oil to reach 10% of primary energy, and gas has only reached 8% so far. There is clearly massive potential in renewables, but BP points to the long-lived industrial nature of energy production as a natural break to the rate at which new energies can grow. The replacement cycle is long, and although consumers can buy solar panels at Ikea, BP believe the major growth for renewables will be industrial investment, which is slower to invest meaningfully.

Finally, BP point to the energy mix as only one element of this equation. Energy intensity and efficiency is where huge gains can be made and this is not getting enough attention. 

BP continue to assert that this switch will be better under a carbon price environment - companies and countries do not yet know the best solution and to assert subsidies and help is less efficient than letting the market solve the problem organically. Companies like BP seek to maximise shareholder value, and a carbon price will make this process easier to establish.