Upstream Also Feeling the Squeeze

Report from the IEA February
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Unlike headline‐grabbing changes on the demand side, which have curbed the 2009 global forecast by 3 mb/d since last summer, the impact of lower prices and the credit squeeze on supply has been less easy to discern. Nonetheless, stripping out downward revisions to the 2008 baseline, forecast 2009 oil supply capacity has been cut by around 1 mb/d in the same period. The concern among market watchers is that the current lower price environment may curb investment and leave inadequate new capacity available when demand growth eventually recovers. That could sow the seed of a sudden reversion to much higher prices,
and further intense price volatility, with all the adverse impacts on economic growth that this would imply. 46% of the net change in our own supply forecast for 2009 has derived from OPEC gas liquids and condensates, with recent OPEC crude cutbacks affecting associated gas supplies and the gas liquids normally stripped out from that gas. Indeed much of the revision for NGLs makes itself felt in adjustments applied this month, notably for Saudi Arabia and the UAE. New projects have also slipped in those two countries and in Qatar, further cutting into hitherto‐expected record growth, although still leaving OPEC NGLs growing from 4.9 mb/d to 5.2 mb/d between 2008 and 2009. 28% of the downward revision for 2009 comes from OPEC crude capacity (here including ex‐member Indonesia), now seen averaging 36 mb/d for the year as a whole, compared with 36.4 mb/d last summer.
There may well be more slippage to come in terms of OPEC capacity with, for example, Saudi Arabia and Abu Dhabi reportedly looking to shave 10‐15% off contractor costs for the longer‐term Manifa and Sahil/Asab/Shah (SAS) projects respectively. Recent comments from OPEC Ministers have also tended to support the expectation that previous capacity expansion targets are now unlikely to be met on the original schedule. That said, our projections for OPEC capacity seem to have borne up relatively well (acknowledging that publicly available data on actual installed capacity are scarce). This is partly because the projections made last year
already factored in project slippage and relatively aggressive decline rate assumptions for most OPEC countries.
This leaves 270 kb/d that has been cut from the 2009 non‐OPEC forecast since last July, net of 2008 baseline changes. Some envisage more downward adjustments to come, with oil company spending tending to flatline or be cut in 2009 compared with 2008. Spending surveys by Barclays Capital and IHS Herold point to a 10‐15% cut in upstream capex for 2009, the first drop in several years. Much of the reduction is concentrated in North America and Russia, where spending looks to be down by 20% or more. In contrast, some NOCs, such as
Pemex, CNOOC and Petrobras seem to be sustaining high levels of spending. Part of the fall in investment is costdriven, since costs for raw materials like steel and cement have already fallen sharply. However, labour and equipment costs have stayed relatively strong.
Indeed industry insiders see typically a 12‐18 month lag between falling crude prices and falling overall project costs. Moreover, while the cyclical component of this
decade’s cost increases is likely to recede, the structural driver for higher overall costs (complex projects in hostile, technologically challenging and therefore capital intensive environments) is likely to persist. A classic example of this structural shift is the Canadian oil sands in Alberta. The list of oil sands project deferrals grows by the week, with up to 1 mb/d cut from industry forecasts of 2015 output.
However, the immediate impact of reduced 2009 spending is likely to derive less from new project deferrals this year and in 2010 (a factor for production levels in 2012 and beyond, given project lead times) and more because of reduced spending on areas like pressure maintenance, fracturing, infill drilling and enhanced oil recovery. Companies take these measures all the time to curb decline in existing, mature fields. Work by the OMR and World Energy Outlook (WEO) oil teams implies net decline for global baseline production around 5% per year. The MTOMR saw that as equivalent to losing 3.5 mb/d of global production capacity every year. This is managed decline, however, requiring heavy levels of spending. If spending is being curbed, even for the short term, decline could accelerate further. An additional 0.5‐1% decline for baseline non‐OPEC supply in 2009 would cut 300‐500 kb/d of supply, effectively eclipsing current expected non‐OPEC growth altogether.
Then there is the question of likely production shut‐ins if oil prices were to fall substantially lower. Although the major resource‐holders in the Middle East enjoy cash production costs for baseload output substantially below $10/bbl, for much of the rest of the world, cash operating costs can lie as high as $15‐20/bbl (although again, a cyclical component of these costs is now likely falling). Estimates for higher cost output such as the Canadian oil sands and US stripper well output (which both account for around 1 mb/d of present output) generally have operating costs in a $25‐35/bbl range. Not much output may be shut‐in because of current field economics, but further sharp falls in prices would begin to undermine even our own relatively modest expectations for 2009 non‐OPEC growth. Detailed production data for the last part of
2008 and the early months of 2009 will be highly instructive in helping to gauge the immediate short‐term impact of lower prices on supply. We will be examining the trends in more detail as that data becomes available in the months to come.