28th October 2014
With Brent having drifted down almost to U.S.$80/Bbl recently, what impact is this likely to have on drilling activity in the unconventional plays in the United States, in particular? Certainly, unconventional resources are expensive to produce and require growing production to fund the “treadmill” development requirements. GCA has examined the numbers for the Eagle Ford and concludes that while better performing companies would still appear to be above the economic threshold for much of what they do, others are certainly likely to feel the pinch. However, there are many factors that will drive short-term activity beyond just oil price, and perhaps it will be the medium-term before a trend based on fundamentals starts to emerge, by which time the dynamics of the situation may have changed again anyway.
- US Domestic unconventional oil and liquid production currently stands at 5 MMbpd and represents 95% of US liquids growth between 2011-2013
- Recent slide of oil price to U.S.$80/Bbl range likely to challenge some, though not all activity
- Average Eagle Ford type well still viable at current prices, but vulnerable if they fall further
- Impact more likely to be felt on companies performing outside of sweet spots, or with challenged financial circumstances
- Rig count in Eagle Ford has been falling for a year, but production still growing; some further modest fall may still be possible before growth is halted
- Complex interaction of factors affecting short term activity before underlying fundamentals assert themselves
- Not just drilling and production; also a risk of new mid and downstream infrastructure being under-utilised if decreased drilling activity
According to a recent report, production from unconventional resources has propelled the U.S. to the position of number one liquids producer in the world. Driven by the co-application and advancement of two 50+ year old technologies (directional drilling and hydraulic fracturing), this boom has also been made possible by the rise in oil prices to U.S.$100/Bbl and more. Ironically, coupled with soft global oil demand and differing priorities between OPEC members, this liquids boom is also helping drive down the price of oil, potentially starting to threaten its own success.
Oil prices have dropped from U.S.$115/Bbl in June this year, to almost as low as U.S.$80/Bbl, with the prospect of the price falling even further. What is more, in North America in particular, producers receive far less than this price at the wellhead. The combination of the price differentials in North America and transportation costs may see a discount of U.S.$20/Bbl or more relative to headline market prices already being realized in some locations. This raises the question of whether, and if so when, drilling activity (and therefore production) will be impacted in the U.S.?
First, it is helpful to understand U.S. liquids production, in particular, the contribution from unconventionals. The EIA reported liquids production at approximately 9 million barrels per day, as of mid-October, 2014. Of this, approximately 4 million barrels per day comes from conventional oil and liquids, and 5 million barrels per day from unconventional oil and liquids.
The EIA identified the Bakken, Niobrara, Eagle Ford, Permian Basin, and Utica/Marcellus as contributing 95% of the domestic crude growth during the 2011-2013 period. This growth has added significant amounts of light crude (35° to 45°API) and significant volumes of natural gas liquids (NGL), as well as associated gas. The mix of liquids comes from the exploitation of different fluid phase windows of the unconventional plays (i.e., the “oil” window of the Eagle Ford Shale compared to the deeper “wet gas” window). These fluid phase windows have different producing hydrocarbon characteristics and therefore significantly different economics.
For example, an unconventional well drilled into the “oil” window of the Eagle Ford may see produced hydrocarbon splits of 75% crude, 10% NGL and 15% dry gas, while a well drilled in the “wet gas” window could see splits of 35% crude, 20% NGL and 45% dry gas. These splits have led many unconventional operators to report estimated ultimate recoveries and production levels for wells in barrels of oil equivalent (boe). Unless that operator’s position within an unconventional play is thoroughly understood, hydrocarbon output value could be easily misunderstood, and its value mis-estimated.
It is also important to understand that not all unconventional wells are created equal, not just as between different plays, but also within individual plays. For example, in the Eagle Ford “oil” window, while an “average” well may start producing at 700-800 boe per day, the range on 90% of the wells drilled could vary between 250 and 1,500 boe per day. Estimated ultimate recoveries could vary as well with an “average” estimated ultimate recovery (EUR) in the Eagle Ford “oil” window being around 300-400 Mboe, with a range on 90% of the wells between approximately 100 to 600 Mboe.
Over the course of several years, many small- to mid-sized operators have shifted their portfolios to an essentially “pure play” unconventional focus to exploit these liquids. These projects require large amounts of sustained capital expenditure to keep production output constant, let alone to increase it, as the initial production declines associated with unconventional wells typically vary from 80%-90% in the first year. In addition, a majority of these projects have been based on an assumption of the oil price being in the order of U.S.$100/Bbl or more. Given the large variability in individual well performance noted previously, internal rates of return (IRR) can vary significantly on a per well basis from negative to over 100%. However, on a consolidated program/play, operators have been able to average IRRs of 15%-30% at this pricing point. This variability makes operators who are not well hedged highly exposed to changes in oil prices.
GCA has analyzed historical production from the key plays in North America to investigate the sensitivity of individual well and play economics to oil price. Using the example of the liquids rich window in the Eagle Ford Shale of the Gulf Coast Basin, GCA examined historical production from approximately 3,000 wells drilled between 2011 and mid-2013. This focus was used to create representative low, mid, and high case type-well profiles of crude, NGL and dry gas, which were combined in GCA’s unconventional field development model, to simulate a development forecast. Using the latest publically available drilling and completion costs, fixed and variable lease operating expenditures, costs associated with gas gathering and treatment, water disposal costs and transportation, the economics of these development plans were examined at oil prices in the range U.S.$70-100/Bbl.
The result is that there is good news and bad news in unconventional development activity within this particular fluid phase window in this particular unconventional play. The good news is that the good wells remain very good wells, even at the U.S.$70/Bbl price point. However, the majority of these good wells are centralized in certain locations where the geology and reservoir characteristics have produced a rock that is easily hydraulically stimulated and contains high amounts of producible hydrocarbons in place.
The “bad” news is that these reservoirs are heterogeneous, and outside of “sweet spots,” oil companies have to drill rock that yields much lower production performance and EURs, leading to marginal and even negative economics for wells drilled at U.S.$80/Bbl oil and some places even at U.S.$90 or $100/Bbl oil. The results of an average type well, with economics run at varying oil prices, is shown in Figure 1 below.
Figure 1 - 1Assumes U.S.$ 7.5MM completed well cost, U.S.$ 4.00/Mscf Gas, with “Average” Type Curve IP of 800 Boepd and EUR of 370 Mboe.
Reality will always be a little different to simple theory. There are many factors driving activity and production that are not simply “today’s oil price”, including the acreage positions, operating performance and operating practices of individual companies, their financing metrics, hedging positions, and the need to drill to hold leases.
Reviewing historical Eagle Ford rig counts and WTI Spot Prices over the past two years it is clear that although there has been an overall decrease in active rigs, the decline does not go hand in hand with the price of WTI. Further, over this period, according to the EIA liquids production from the Eagle Ford has almost doubled from around 800,000 to around 1.6 million barrels per day today and is still rising (Figure 2).
While there is a suggestion that the drop in rig count in July 2014 (see Figure 3) may be reflecting, at least in part, the steep drop in oil price, it has recovered somewhat in the past month and has been on a declining trend anyway for the past year. Thus, other factors are also playing a role, including the increase in drilling efficiencies (i.e., fewer rigs necessary to drill same amount of wells) which would account for the continuing growth in production. However, it is not clear to what extent the recent steep drop in oil price over the past 3-4 weeks has yet to play out and, to the extent that today’s activity levels are reflective of an investment climate in the U.S. $100/Bbl range, it is not unreasonable to expect that at U.S.$80/Bbl there will be an impact.
The timing and degree of any such impact can also be examined based on EIA data. Based upon the steep production decline associated with newly drilled wells, the EIA forecasts a “legacy” production decline of around 120,000 Bbl/day in the coming month at current production levels. However, this is also forecast to be more than offset by an increase of around 150,000 Bbl/day from new wells, resulting in a net increase in the month of around 30,000 Bbl/day.
Although simplistic, and ignoring any impact from well inventory and completion timing, with around 200 active rigs in the basin this would imply that each rig adds approximately 750 Bbl/day each month. Therefore, to offset a decline of around 120,000 Bbl/day would require around 160 rigs to remain actively drilling. The laydown of some 40 rigs from the current level over a short time period is not unprecedented, with an example being the Haynesville Shale which saw a lay down of 33 rigs within a 2 month span, with a high of 11 rigs being dropped in a single week.
Whether or not activity is set to decline, and production flatten or decline, remains to be seen. If this is the case it will not just be producers and service companies that are impacted. Major U.S. onshore midstream and downstream expansion projects are underway based on the historical increase in drilling activity and production output, which has been seen over the past few years; however, with an unforeseen decrease in drilling activity, these pipelines and processing plants may find themselves at under-capacity.
While no one is sure where oil prices are headed, and it may be too early to tell how industry will react, it is crucial for any company exposed to unconventional production and economics to understand exactly what the range of outcomes of their investments could be. Tens of billions of dollars has been invested in U.S. unconventionals by all sectors of the oil and gas industry across the U.S., and this analysis on Eagle Ford activity levels and production output can be readily extrapolated to other U.S. onshore unconventional basins that experience the same steep new drill production decline rates and exposure to oil price.
There is plainly a lot more to be done to understand better how all the activity drivers interact with each other, and the lead/lag effects between one parameter changing and others moving accordingly. However, for any player exposed to the unconventional resource plays in North America, gaining a deeper insight is going to be essential if investment and hedging strategies are to be properly developed.
If you are interested in following up on the contents of this article, or would like to discuss how it might be applied to assist your company, please contact your local GCA office, or in Houston call (713) 850 9955 and ask to speak to Bob George or Neil Abdalla.
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