The recent rally in crude prices looks more like a head-fake than a sustainable turning point, suggests Citi’s Ed Morse, noting that short-term market factors are more bearish, pointing to more price pressure for the next couple of months and beyond. While the shape of the oil price recovery is unlikely to be ‘L’-shaped in their view (more likely ‘U’, ‘V’, or ‘W’-shaped recovery), Citi warns the oil market should bottom sometime between the end of Q1 and beginning of Q2 at a significantly lower price level in the $40 range (perhaps as low as the $20 range for a while) – after which markets should start to balance, first with an end to inventory builds and later on with a period of sustained inventory draws.
The recent rally in crude prices looks more like a head-fake than a sustainable turning point — The drop in US rig count, continuing cuts in upstream capex, the reading of technical charts, and investor short position-covering sustained the end-January 8.1% jump in Brent and 5.8% jump in WTI into the first week of February.
Short-term market factors are more bearish, pointing to more price pressure for the next couple of months and beyond — Not only is the market oversupplied, but the consequent inventory build looks likely to continue toward storage tank tops. As on-land storage fills and covers the carry of the monthly spreads at ~$0.75/bbl, the forward curve has to steepen to accommodate a monthly carry closer to $1.20, putting downward pressure on prompt prices. As floating storage reaches its limits, there should be downward price pressure to shut in production.
The oil market should bottom sometime between the end of Q1 and beginning of Q2 at a significantly lower price level in the $40 range — after which markets should start to balance, first with an end to inventory builds and later on with a period of sustained inventory draws. It’s impossible to call a bottom point, which could, as a result of oversupply and the economics of storage, fall well below $40 a barrel for WTI, perhaps as low as the $20 range for a while.
Is a ‘new oil order’ replacing the old order?
Markets have, in Citi’s view, correctly depicted the heart of the lower price oil environment as a result of a conflict between markets and marketing influence, or more directly between the impacts of the shale revolution on OPEC’s ability to drive a significant “permanent” wedge well above production costs to maximize revenues for OPEC and other oil producing countries. No matter what the ultimate outcome, it looks exceedingly unlikely for OPEC to return to its old way of doing business. While many analysts have seen in past market crises “the end of OPEC”, this time around might well be different.
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There are three critical factors in the future: supply, demand and inventories.
How rapidly is supply likely to adjust to low prices?
From a supply perspective, $50-or-even-60/bbl is unsustainable in the medium-term as not enough future oil supply is generated to meet future oil consumption:
1) up to half the world’s future projects are uneconomical at oil prices below $50/bbl;
2) corporate cash flow generated at $50/bbl is not enough to meet debt, shareholder and capex requirements and pullbacks on brownfield spending should accelerate existing decline rates; and
3) $50/bbl cuts government revenue budgets, up to half in some cases, and with domestic spending hard to cut meaningfully, hence NOC investment has to be revised down sharply. This means supply cuts are on the way, and the lower and longer oil prices stay, the more deferred supply will be curtailed, especially given the myriad implications this has for geopolitics. Lower prices, in short, create greater political risk of supply disruption in distressed economies, including among other Nigeria and Venezuela. By 2016, we expect non-OPEC supply to be declining y/y, by ~0.2-m b/d, from a combination of US shale curtailment and accelerated current field depletion.
For now however, crude supply has significant momentum as prices above operating costs mean there is little reason to pull back output. US production is still growing at 1.1-m b/d y/y, Atlantic Basin waterborne loadings are up 665-k b/d y/y to 9.6-m b/d in January-February, and Brazil and Russian output reached record levels in December, of 2.5-m b/d and 10.7-m b/d respectively, with Russia maintaining this level for January. Saudi Arabia, Iraq and Iran continue to cut their Official Selling Prices (OSPs) to Asia in a bid to retain market share meaning supplies out of the Persian Gulf aren’t expected to decline (by choice) soon. Iraq exported a record 2.7-m b/d in December from Basrah, and Federal and Kurdish exports are growing in the North, reaching 300-k b/d in January. This wave of supplies has been depressing prompt prices and a pullback isn’t expected until 3Q’15, or 2Q’15 in our “V” scenario where oil may need to price down to $30/bbl to shut-in current production.
The biggest revision to oil supply growth is coming out of the US, with recent growth rates of over 1-m b/d y/y for crude output overwhelming global oil markets. While there could be a range of responses, we expect that shale producers may end up cutting rigs by around 50%, while some 0.2-m b/d of marginal oil wells could see shut-ins. (By itself, this could mean US crude production growth could slow to ~0.6-m b/d y/y in 2015, or ~0.8-m b/d y/y for crude and NGLs together, and down to 0.25-m b/d y/y in 2016 for crude output growth, or ~0.45-m b/d for crude plus NGLs.) But given prices might drop significantly in 2Q’15 as US storage tanks near critical levels, US shale producers may also drill but not completing wells in 2Q, building an inventory of drilled-but-not-completed wells. These could be brought back in 2016, or when futures prices recover and could be hedged out.
Falling oil prices have led to parallel processes of supply adjustment. First, US shale producers were cashflow negative on aggregate, with capex higher than cashflows, with high-yield debt bridging much of this gap. As production volumes grow quickly, the industry was set to move to a cashflow neutral position in 2014, and was expecting to go increasingly cashflow positive in 2015 and onwards. The oil price drop scuppered that outlook. Capex has therefore been cut back to defend balance sheets. Second, as the oil price fell, less productive shale acreage became uneconomic. Taken together, company announcements to reduce drilling activity in 2015 and onwards, and focusing remaining activity in the most productive core areas of the major shale plays makes sense. See “Is the falling US oil rig count really driving an oil price turnaround?”, where the rig cuts seen so far in 2015 are meaningful, but not so much as to bring US production growth to anywhere near zero, let alone negative, particularly if productivity gains are substantial.
In our report, “Catching the Knife – call on shale is a new balancer for oil markets”, we explored the level of capex/rig cuts to get the US oil and gas industry as a whole to cashflow neutral. We found that with only modest productivity gains, a ~50% rig cut could bring the industry to cashflow neutral in 2015, moving to cashflow positive in 2016 as production volumes continued to grow, and prices could recover. With such a 50% rig cut, US oil production growth could still be +0.6-m b/d y/y in 2015, flat y/y in 2016, and growing again in 2017. So far, company-announced capex cuts look in the 20-40% range, and so far, total active US oil rigs are down 30% from the peak, though most of the falls have been in vertical and directional rigs.
But given the lagged supply response, storage is needed to bridge the gap until the supply-demand overhang shrinks and reverses. This looks like it will be a major obstacle in 2Q’15, and could cause a production crunch in the US. When crude storage tank-tops look like there are within range of being hit, WTI is likely to move into steep contango, and the Brent-WTI price differential should blow out to reject foreign crude imports and incentivize US crude exports – this would be unless the Atlantic Basin struggles to absorb more barrels, but it looks like more floating storage is available with tanker rates taking a breather in 2Q due to refinery maintenance.
Aside from shale’s curtailment, the pullback of brownfield and maintenance capex is expected to accelerate global decline rates for current conventional production. Citi’s latest estimate for cuts to brownfield and maintenance capex is ~15% for Big Oil and with current decline rates of 5-6% we see global depletion rates increasing by ~1% by the end of 2015. A pull-back on maintenance capex feeds through to accelerated decline rates as spending is diverted away from more mature fields which are abandoned earlier than previously planned, lifting the aggregate amount of lost oil from producing wells. In mature conventional plays such as the North Sea, where inflating costs and high taxation are already an issue, this should be particularly impactful, and we expect 100-k b/d declines this year and the next, compared to flat growth at $100/bbl.
Meanwhile, the US has significant numbers of marginal oil wells that could be impacted by low oil prices, particularly in 2Q’15. There are now some 500,000 wells in the US that produce less than 15 b/d, averaging around 2 b/d, and altogether accounting for ~1-m b/d of the US’s over 9-m b/d of oil production. These are particularly concentrated in Texas, Oklahoma, Kansas, and California, but are also spread widely amongst other states (see table below). We factor in some 200-k b/d of US marginal well production that could be at risk of shut-in, though this could end up being higher.
Russia remains a special case, with the added complication of sanctions on drilling technologies and external debt financing along with previously anticipated Western Siberian field declines. In and of itself the oil price isn’t expected to directly hit Russian production given that the Ruble depreciation and Ruble-based costs of a large number of Russian oil firms act as a counterweight. External debt financing is an issue though, especially for Rosneft which has large short-term US dollar debt commitments and recent Ruble-based debt issuance has precipitated further Ruble depreciation in anticipation that the cash raised will be used to buy US dollars. A combination of decreasing oil (and gas) revenues, access issues to drilling rigs needed to maintain current production levels, difficulties in managing the acquisitions of BP-TNK and Bashneft, and Rosneft field declines lead us to expect Russian output to drop by 200-k b/d y/y in 2015. Further sanctions also can’t be discounted meaning further risks to this number to the downside.
Petrobras, along with a host of management issues, could see spending cut as much as 30% this year and Brazilian production growth is expected to slow to ~100-k b/d y/y. And Colombian production is expected to decline by ~100-k b/d due to investment grinding to a halt, a situation Venezuela also finds itself in.
Canadian production growth is also expected to slow, especially given where oil sands projects sit on the cost curve, but with the Sunrise energy project, Kearl’s expansion and the Nabiye project all coming online this year, output is still expected to grow by 110-k b/d y/y with perhaps another 50-k b/d next year. China is also likely to struggle with 30-40-k b/d declines in the Daqing field set for 2015 due to the high cost of development of the field.
Several OPEC suppliers are expected to have y/y declines as a result of the price drop. Venezuela and Nigeria, who rely so heavily on oil revenues, are hurting from the 50% decline in oil prices, particularly as they lack the FX reserves of the GCC and Russia. Venezuela, in particular, with a chronic lack of investment in up- and-downstream, is expected to see a 200-k b/d decline in output by year-end. The status quo remains in Libya with supplies likely to bounce around in the 0.3-0.5-m b/d range whilst Algerian production is expected to be down another 100-k b/d y/y. Iraq is the shining light in OPEC, and despite issues with ISIS and southern field and port infrastructure, output can grow by 300-400-k b/d y/y in 2015. This is predicated on the fact that relations between the Kurds and Baghdad at least stay as they are, allowing both Federal and KRG exports to rise from Ceyhan to perhaps 400-500-k b/d this year. Record Basrah loadings in December give cause for optimism but January data show declines of ~300-k b/d to 2.5-m b/d highlighting a consistency issue that has plagued Iraq.
How far can demand growth move the needle on global balances?
Just as low prices have a negative impact on supply, so too do they have a positive impact on demand, both directly through lower prices on petroleum products and indirectly through positive impacts on GDP. But the impact is likely to be muted and not nearly as robust as historical experience would indicate due to one-time and structural changes happening in the market. Citi expects oil demand growth to reach 1.3-m b/d y/y in 2015, with OECD growing by 0.12-m b/d and non-OECD growing by 1.19-m b/d; in 2016, demand could rise by 1.2-m b/d, as OECD demand could resume falling after a price increase y/y, down 0.15-m b/d y/y, partly offsetting stronger growth in non-OECD countries.
The net positive impact on global GDP could be sizeable, adding to the potentially stimulative effect of a number of looser monetary policies globally announced in January. The low oil price impact on economic performance should be stronger on consuming countries, more than offsetting challenges faced by producing countries. Even with the sharp drop in prices starting in the middle of 2014, Brent prices still averaged $99.5/bbl last year. Hence, a nearly 50% drop in price in a more than $3 trillion market is expected to raise consumers’ disposable income, lower input costs and ease government finances for those with large-scale demand-side subsidies. Economic performance later on could exceed current forecasts. The negative impact on producers may not have as sizeable an effect as subsidies or support tend not to be cut immediately, while the slowdown in petrodollar recycling, which is mainly channeled through the asset markets, also has less of an immediate effect on consumption. However, a currency war due to competitive devaluation and further monetary stimulation could start to weigh on the global economy. Nonetheless, at this point, impacts from oil and monetary loosening still look to be positive.
Taken together, a sharply lower oil price level should boost demand through two channels: (A) the direct impact of lower prices, and (B) the support given to global economic activities as a result of lower fuel costs.
(A) Direct impact on oil demand: transportation fuel consumption, especially in countries with no or very small subsidies, should see a greater rebound in demand, as the cost savings are directly passed to consumers. OECD countries are major beneficiaries, especially those in North America. In contrast, some non-OECD countries have retail price controls or provide subsidies that enable consumers to be partially shielded from higher prices in recent years; with the oil price drop, some countries have only reduced retail product prices by a smaller magnitude, so that governments could cut subsidies and reduce their fiscal burden. Non-transportation fuels could see smaller growth y/y as a direct result of lower prices, where sectors such as industrials, power generation and other miscellaneous uses dominate this segment of oil demand. These sectors would only use as much oil as needed to meet the ultimate demand of their own products (or electricity generated.) Hence, lower oil prices could stimulate a slight, but not large increase in demand from these sectors.
However, as Citi expects Brent prices to rise from $54/bbl in 2015 to $69/bbl in 2016 in our base case, the decline in OECD demand could partially resume. The initial phase of nuclear restarts in Japan should also reduce fuel oil demand more than LNG demand. This explains why global oil demand growth should be smaller in 2016 versus 2015.
(B) Indirect impact on oil demand: Lower oil prices should provide a boost to economic performance globally by reducing the cost of fuel and feedstock through two transmission mechanisms. First, it generally takes time for better economic performance to progress through to increases in real oil demand. Although the increase in consumer disposable income should lead to a more immediate increase in the consumption part of the GDP equation, the price impact on GDP and GDP-induced oil demand gain is expected to be stronger in 2016 than in 2015. Consumers could adopt new habits in oil demand; businesses, after seeing possibly stronger consumer sentiment and lower cost structures, should look to raise production and investment, especially in countries with strong manufacturing/industrial/export sectors. This benefits many non-OECD countries. The wait for industries to ramp up is also where the delay in oil prices impact on GDP comes in, but this also means that the ripple effect on the economy from lower oil prices could last for many quarters with stable prices.
Beyond secondary and tertiary stocks, primary crude storage should play a central role in how prices could rebound. Just as an oversupplied market shifts prices to incentivize storage, a rebalancing market that starts to draw on inventories will also affect prices in its own right. As markets work through stored barrels and unwind the storage trade, the reverse dynamics apply. Prompt prices should rise to close the storage arb, collapsing the contango curve structure. This dynamic can create the conditions for a V-shaped recovery as oversupply wanes and demand catches up.
Thus, in our balances, global oil inventories are on the rise into 2Q’15, but begin to draw down from 3Q’15 onwards as summer demand kicks in, and as supply pulls back sharply from 4Q’15.
In the US, 2Q’15 sees tank-tops potentially challenged, though prices likely move to forestall this, which could adjust US production, imports and exports to draw down stocks, and should correspond with a widening of the Brent-WTI spread as both Brent-LLS and LLS-WTI widen to flush out stocks from Cushing to the Gulf Coast, and from the Gulf Coast out into the Atlantic Basin.
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In short, it looks as though there should be a sharp recovery in prices by winter 2015/16, and as a result of that, there should be an enhanced stimulus for US shale production growth going forward. This could well overwhelm demand growth and bring prices down again, in a ‘W’ shape.
This is the first experiment with dealing with shale supply, and the first time in which the world is getting used to a new oil order, with a “call on shale” replacing a “call on OPEC” as a new market benchmark. As a result, the likelihood is that the sharp price recovery should stimulate more production growth in North America again, and all other things being equal, bring about another decline in prices, after which US production growth is likely to moderate.
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