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Are Operators to Face-Off with Oilfield Service Providers?


Talking with multiple oil field service companies over the past few quarters, the discussion around costs is weighing heavily on many minds. As oil prices have risen over 50% from lows in 2016 (Figure 1) service costs have stayed flat to declining; many oil field service companies are losing money on every transaction. In a report on FuelFix there were over 108 oilfield service bankruptcies from 2014-2016, some as large as one billion dollars. Some might argue that OFS companies took the brunt of the downturn losses in terms of people, work, and money as E&P companies forced costs to unsustainable levels to meet their obligations.

Figure 1: WTI Spot Price Q4 2013 to current (Source: Fuelfix)

The issue ahead can be boiled down to market share vs profitability – keep prices low to gain market share or raise costs and begin to generate returns. Depending on whether a company is public or private, has notes coming due, etc. can drive this discussion in multiple ways. Using engineering data from Drillinginfo we can see that production from wells over time has increased per 1,000’ of perforated lateral and overall (Figure 2). The reason we look at production in a normalized fashion is to see if we are incrementally increasing efficiency in production— meaning we are getting higher returns per normalized foot. In some instances we will see that production is increasing un-normalized but decreasing when we normalize. This leads to the question of whether we are drilling longer laterals which is increasing overall production but producing less efficiently per normalized foot. This is sometimes inevitable when down-spacing occurs in development plans but can also mean that the cost to drill a longer lateral is less than the overall incremental return in production even though we could be producing more from a shorter lateral per normalized foot.

Figure 2: Proppant Volume over time per 1,000 ft of perforated interval

Figure 2.1: 12 Month Cum Production Per 1,000 ft of perforated interval

Proppant volumes have also increased across all basins but the costs associated with increased proppant volumes and various other chemicals used in completions are vastly outweighed by the increased production. In basins such as the Midland and Delaware we are seeing an increase in over 30% YOY (year-on-year) production growth when looking at vintage type curves. Even though this increase might not continue as we move into downspacing sections, the increase in production and subsequent EURs will yield higher returns than older wells using lower proppant volumes.

Figure 3: Delaware Basin Vintage Decline Curve

Figure 4: Midland Basin Vintage Type Curve

Figure 5 (partial data for 2/2017) shows what the rig count is telling us—that most basins are seeing either stable or increased activity as prices begin to stabilize or slightly increase.

Figure 6 shows the incremental change of DUCs from that drilling activity over the last year; we have decreased the overall amount of DUCs but by very little. During October and November of 2016 we can see we increased the number of total DUCs before completing a large quantity in December. As more wells have been drilled in the past couple months the overall DUC count is staying flat meaning we are completing almost as many wells as we are drilling. Again, these returns are being realized by E&Ps but have not translated to service companies. With more rigs coming online, an increase in the DUC count can occur when there are not enough completion services to go around.

Figure 5: Wells drilled over past two years by basin

Figure 6: DUC count over time across the US

Job cuts in excess of $500k over the years have led to a downturn in qualified personnel, not including the equipment that has been sitting idle.Cannibalizing equipment to keep other equipment running, foregoing services on equipment to keep cash flow positive impedes the ability of the industry OFS to bring on new crews. Currently companies are waiting 3 months for a new fleet to be built; how will this change if demand for new fleets ramps up 50%? Efficiencies in completions can only go so far as the time it takes to complete a well; lean six sigma practices can be used for supply chain management but doesn’t help a lot if the supply chain is empty.

Another discussion concerns sand and various chemical costs. Currently we have not seen much of an increase in costs of proppant but there have been discussions of costs rising 10% or more on certain types of proppant. This is due to multiple factors—increased activity, longer laterals, and increased proppant volume per ft are raising the volume of sand needed per job. Compared to 2014 (graphic on sand per 1000 ft over time) we have seen an increase of 100% in the Delaware in terms of sand volumes and 38% in the Midland. The average horizontal well in the US is using 9.2 million lbs of proppant per well with some testing upwards of 30 million lbs. Begin to multiply those figures by the average number of wells being completed per year and compare it to the output of sand mines across the US. Compare it to the associated costs to transport that sand by rail and truck to location and then contemplate continuing to increase the average total volume per well as we have in the past couple years.

Figure 7: Proppant volumes horizontal wells completed onshore US

Figure 7.1: Proppant Over Time Delaware Basin

Figure 7.2: Proppant Over Time Midland Basin

The demand this has on mines is incredible. With operators moving to finer meshes and mixes, it only makes sense for proppant suppliers to raise prices to counter the rising demand. These costs will be directly passed on to the E&Ps who will have to deal with the rising costs of in-demand services. The clash between these two parts of industry could be economically compelling since publicly traded E&Ps have issued guidance on returns based on specific costs which will be inaccurate if service costs rise. The question is, how many companies will push back? Figure 8 looks at the breakevens of Operators in the Permian with 20% returns at $50 WTI and $3HH with flat service costs on the left and 20% increase in service costs on the right. One can see the number of Operators and regions that become out of the money just in the Permian; this will affect other regions that have higher service costs due to location, etc. in a negative way.

Figure 8: In the money operators with $50 WTI, $3 HH, and flat service costs and 20% increase

Currently, service companies have the upper hand. Many are fully contracted out for services. Companies late to the game will have to pay to build fleets or wait in line, adding additional costs to completion schedules that will have to be met. If pricing goes back down, these operators will be on the hook for the fleets they helped build which would lead to the same issue we saw during the downturn with rig contracts; E&Ps paying to break the contract. On the other hand if pricing is sustained this could give them a leg up with a fleet built for their wells. Service companies are starting to work for who they want, not for who will pay, leading to a scrutinizing of companies that are late on payments, poor partners, etc. Holding the line for E&Ps might not be possible. Rising service costs and subsequent downward pressure on returns will hopefully not start another vicious cycle between the two sectors.

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Phillip Dunning

Prior to joining the company in early 2016, Phillip worked as an asset development engineer in the Appalachian basin and later at an upstream Private Equity firm focusing on equity investments in unconventional plays and royalty/mineral acquisitions. Phillip has advised companies on deploying capital, raising money, and A&D and has helped startup numerous O&G companies since 2013. Phillip is an Engineer by education with a B.S in Engineering from The Ohio State University and a M.S in Petroleum Engineering from The University of Louisiana.

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