July 2015

Shale exposed service companies are taking a hit


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“Floater market facing challenging times, retirements to reach historical high”

 

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"The search for price cuts in the oilfield service industry"

 

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RYSTAD ENERGY PRODUCT HIGHLIGHTS

Oilfield Service Databases
• DCube (Demand Database): Historical and forecasted opex and capex for global oil and gas fields, split on supplier segment and geography

In the latest DCube version (June 2015) short term oilfield service purchases are expected at -8.8% CAGR for 2014-2016. Largest market contraction expected in EPCI.

• SCube (Supplier Database): Reported revenue from oil service companies split on the same supplier segments and geographies as DCube

The July 2015 version of SCube shows that the announced spend by E&P companies have materialized into -18% revenue decline in the first quarter of 2015 compared to last quarter of 2014. Worst is it for companies exposed to North America where first quarter is down with -25%. 

• RigCube (Rig Demand & Supply Database): Global, offshore rig demand (rig count) and supply based on bottom-up, field-by-field activity analysis

The June 2015 RigCube version shows a decrease of 26 units in floater demand from 2014 (262) to 2015 (236). Jackups to be decreased with 36 units from 2014 (408) to 2015 (372).

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Low oil prices and lowered activity have made a severe impact on the service companies exposed to North America. Their revenues were down 25% in the first quarter – a much higher decrease than the average of -18% we see on a global basis.

Figure 1 shows how the largest service companies in North America onshore have been punished for being heavily exposed to the North American market. While the global average decline in revenues has been about 18%, companies exposed to North America have had their revenues in North America declining by 25%. Worst situated are Baker Hughes, RPC, Patterson-UTI with more than 30% drop suggesting that they are losing market share in the first quarter. Better off are OCTG and equipment manufacturers, which still float on longer lead times. Land drillers such as H&P also saw the benefit of termination fee on their top line for the first quarter.

How far we should expect the onshore North American market to decline depends on both pricing and activity, especially within the development of shale resources. For prices, we have already observed the following for the first quarter.

Well configurations: Well configurations are expected to improve as more shale plays move up the “development ladder”. Still, we observe increased laterals and fracture stages on average for shale wells in North America. This increases the well costs in the same magnitude (+1%) as we saw in 2014.

Efficiency gains: As E&P companies continue their search for more efficient operations, we see large savings for rig rental and associated day rate services. Companies are now focusing on “standard” wells with less experimental wells. In addition, they are terminating the least efficient part of their contracted rig fleet, which in turn increases the overall efficiencies. The full impact on the well costs is a 7% decline for 2015.

Unit prices: The largest cut in the well cost will be obtained by the large pricing power gained by E&P companies when the activity is cut by 35% on average. Service companies now fight over the few contracts that are available in the market. They reduce their margins and enforce cost cuts further down the value chain. In total, a 16% unit price reduction may be achieved in the first half of 2015.

In the first half of 2015, we expect the average well cost to decrease 22% compared to 2014. Service price deflation accounts for the majority of the compression. We expect to see deflation in both the drilling and completion costs. About 42% of the well cost is drilling cost and encompasses rig contractors, drilling fluids, drilling services and OCTG. Rig rates are expected to be deflated by 15% as margins will be halved. We observe a large oversupply by many drilling fluids providers and large price cuts above the 20-mark to be realized. This is less so in the OCTG market where prices have shown to be more robust in the first quarter due to solid inventories. Completion cost makes up about 50% of the well costs and includes hydraulic fracturing as its main component. This cost is estimated to decrease by 17% as there is a vast overcapacity of frack fleets in the market and market consolidation is inevitable. The wellbore construction and completion is the second large cost element and a 15% reduction is also plausible within this segment. Surface costs and other services make up 8% of the well cost and are also expected to adapt to a new low activity environment and decrease by 15%. The weighted impact on the well cost yields a 16% reduction in service prices.

Figure 3 shows the revenue for the 70 largest service companies in North America. In 2014 they had $120 billion in total revenues, about half of the capital-driven oil service market. The first quarter of 2015 revealed that these service companies reported a decline in revenue of 25% compared to the fourth quarter of 2014 or -14% compared to the first quarter of 2014. We expect revenues to decrease further into the second quarter as the well count decreases by an additional 10%. The second half of 2015 will be marginally healthier based on slight oil price improvements.

The achieved pricing pressure by E&P companies has resulted in service companies reducing their margins and cutting costs. The average EBITDA margin for North America has been ~15% over the past years. Already in the first quarter of 2015 we have seen this drop to 10% on average, similar to the first quarter of 2009. With even lower activity in the second quarter and larger low price contract penetration, we expect margins to go further down towards the minimum observed in 2009, with a margin average of 7%. Of the total unit price deflation of 16%, half will be realized through margin cuts and the other half through cost reductions and margin pressure down the value chain.

Having examined the development of the well cost and unit prices we can now combine this with the expected activity outlook for the oilfield service market. In 2014, nearly $150 billion was directed into the oilfield service shale industry in North America. About one third ($50 billion) will evaporate this year due to less activity and cost compression. Completion services will be more affected compared to drilling, as a significant number of wells will be left uncompleted and hydraulic fracturing will take a large price cut. Operational costs will be more or less flat in 2015 even though the total number of active wells increases.

The year 2016 will barely see an increase of the market, and the market is first expected to improve in 2017 when the oil price is likely to be around 80 $/bbl (Brent price).