Hydrocarbons are lighter than water. Generated deep within the earth in source rocks, they will migrate upwards towards the surface due to buoyancy. Their movement is typically stopped, when they reach an impermeable layer of rock, a seal. In the best case, the rock below the impermeable layer is either highly permeable and/or dominated by natural fractures. Those properties are typically found in two broad groups of sedimentary rocks: sandstones and carbonates. Such a scenario is called a hydrocarbon trap and most of conventional oil production originates from traps. Nevertheless, the migration process does not always work in a perfect way. Some hydrocarbons get stuck in formations with low permeability or near the source rocks. Such rocks are then called oil-bearing shales and the oil in it is called tight oil. The most known oil-bearing shales in the US are the Bakken Formation, Pierre Shale, Niobrara Formation and Eagle Ford Formation. Those are also the fields, where most of the recently added production in the US comes from. The rise has been possible because of the spread of a method called fracking, which basically means to try to generate artificial fractures. The fractures provide then a flow path for the oil and gas.
Oil-bearing shales should not be confused with oil shale. Oil shale is fine-grained rock containing kerogen (an intermediate product in the formation of hydrocarbons). It is estimated that world deposits are up to 5 trillion barrels, the most prominent one the Green River Formation in Utah, Wyoming and Colorado. Despite that huge potential, production of oil shales nowadays is confined to Estonia and some parts of China. The reason for this is the expansive process that is necessary to produce crude oil from kerogen, as one would have to copy reaction that occur naturally deep within in the earth (pyrolysis). To sum this up: oil shale is incomplete oil without much economic relevance today, while tight oil is fully finished oil that is produced with fracking.
Due to the high increase of tight oil production in the US, its influence on the world oil market has risen dramatically. In 2013, the IEA even claimed that the surge of unconventionals in Northern America has led to a worldwide supply shock that would reshape global markets. Nevertheless, one should not forget that tight oil production is still more sophisticated and needs more technology than conventional oil production.
The recent drop in the price of oil has fueled the debate about the actual production costs in tight oil plays. Nevertheless, estimates differ widely from source to source. Reuters offers a wonderful compilation of this issue. The wide variety is especially troublesome, as most analysts just state their estimates, but do not explain their methodology or which kinds of costs exactly they take into account and which ones not. Additionally, they mostly focus on costs for different tight oil plays. The approach followed in my articles is different. I take all costs into account including administration and interest costs and I segment costs by companies, not by oil fields. I believe this is the most reliable way, as it does not need to include complex geological and economical estimates and hypothesizes, but focuses exactly on what companies actually had to spend to get one barrel out of the ground. Furthermore, annual statements have to comply with accounting standards and are therefore easily comparable.
The boom in tight oil has led to the appearance of a huge number of companies. Some of them are traditional oil producers that jumped on the bandwagon of tight oil. Others are newcomers with huge entrepreneur spirit and sufficient funding who just bought some acreage and started to drill and frack. Nevertheless, the mere numbers of companies is stunning. At first I thought I can handle production costs of tight oil companies in three or four articles, each addressing a similar number of companies. In the meantime, I have noticed that if I want to finish production costs for 2013 in due time (that is before the publishing of the 2014 annual reports) I need to hurry up and increase the number of companies per article. In some of my recent articles (part I, part II, part III) I have already published costs of 14 different companies. In this article, I add the results of eight additional companies: Abraxas Petroleum (NASDAQ:AXAS), American Eagle Energy (NYSEMKT:AMZG), Antero Resources (NYSE:AR), Callon Petroleum (NYSE:CPE), Cimarex Energy (NYSE:XEC), Clayton Williams Energy (NASDAQ:CWEI), Diamondback Energy (NASDAQ:FANG) and Energen (NYSE:EGN). To finish up with tight oil production costs in 2013, I plan to write another 2 articles which should be finished by mid-January.
Oil is hardly ever produced as pure liquid. Normally it comes as a mixture with natural gas and gas condensate. Although I only consider companies here, that mainly lift oil, they also produce significant amounts of gas. Hence, it does not make much sense to apply costs to the production of oil alone. To deal with this issue the concept of barrel oil equivalent - boe - has been perceived. 6000 cubic feet of gas at standard conditions are about one boe. All costs mentioned below refer to one boe, meaning that are the costs related to the production of 1 bbl of oil, 6000 scf of natural gas or a combination of both. Let's say the price for 1 barrel of oil is around $100 and the price for 1000 scf of gas is about $6. This means, revenue from 1 boe of oil is higher than revenue for 1 boe of gas ($100 versus $36). As there are also fields that only produce gas, this article tends to underestimate the costs of oil production.
Commonly, costs are divided in costs that can directly be related to production (cost of sales) and costs that cannot directly be related to output (overhead). However, many oil companies are also active in downstream and midstream or other economic sectors (e.g. Exxon Mobil in chemical engineering). Hence, I have divided sales, general and administration expenses (SG&A) by total revenues and multiplied it with the revenue of the E&P division to get SG&A for E&P. I did the same for any similar type of cost (marketing expenses, R&D) and for financial expenses. Depreciation of assets, on the other hand, can be directly linked to oil production.
Costs of sales are divided into 3 sub-categories:
- Exploration costs
- Lifting costs
- Non-income related taxes
Exploration costs are costs related to all attempts to find hydrocarbons. This category includes cost for geological surveys and scientific studies as well as drilling costs.
Lifting costs are the costs associated with the operation of oil and gas wells to bring hydrocarbons to the surface after wells (facilities necessary for the production of oil) have been drilled. This figure includes labor costs, electricity costs and maintenance costs.
Non-income related taxes: as production of hydrocarbons is such a lucrative business, governments also want to have their shares. There exists an abundance of different model how the state can profit from hydrocarbon production (profit sharing, royalties, etc.).
It might be, that different companies use different categories for the same type of expenses, but eventually the sum of all costs should be their total cost for producing 1 boe.
The following figure shows the pattern of the cost model:
In a number of recent articles I have applied the same methodology on a number of oil companies from all over the world. The links to the articles can be found below:
- Majors I and II
- Independents I, II and III
- Oil Sands I and II
- Tight Oil I, II and III
- European Former NOCs
- Gas I and II
Application on 8 Tight Oil Producers
As mentioned above, I have applied the cost model on 8 tight oil producers. It is important to note that some of the other E&P companies I have investigated so far also produce oil from tight sources (especially the bigger ones). Nevertheless, tight oil production represents only a small percentage of their total production. As those companies do not specify their costs for certain fields, I could not include them in my investigation about tight oil production costs.
The first company investigated in this article is Abraxas. Most of the enterprise's assets are located in the shale plays of the Rocky Mountain region (Bakken, Three Folks) and in the Eagle Ford play. American Eagle is the smallest of the eight companies in this article. It was created in 2005 and concentrates on the Bakken and Three Folks plays. Antero is special in at least two issues: at first it only produced a small percentage of liquids (it would more correctly be called a shale gas producer). Secondly, it became victim of its own success in 2013. It booked a large gain in derivatives and had to pay a stock based compensation of more than $360 million. Using my methodology I have always booked such expenses as general costs (as they are merely part of the compensation). When I did so in Antero's case, SG&A costs were affected significantly and increased to more than $14 per boe, among the highest value seen so far. No wonder, that final costs exceeded revenue significantly. After its foundation in 1950 the company was mainly active in off-shore operations. In 2009 it started a strategic repositioning and shifted its focus to the Midland basin. Cimarex is also active in the Permian basin and has additional mid-continent operations (Anadarko Basin, Texas Panhandle). The company's largest investment area is the Cana-Woodford shale play. Clayton also offers drilling rig and midstream services, but they only contribute a small percentage to the company's total revenue. Most of its sales the enterprise gets from the Delaware Basin, a sub-basin of the Permian basin. Due to a $90 million impairment, Clayton accounted for a book loss in 2013. Diamondback focuses as so many of its competitors on the Permian Basin, and there on the Wolfberry play. Energen is the last company investigated in this article. It is also active in the midstream distribution of gas. Its efforts are focused on the Midland Basin and the San Juan Basin. It also had a stake in the Black Warrior Basin, but it was sold in 2013 as it did not fit into the long term strategy of Energen. Together the eight companies produced 106 million boe in 2013, a daily production of roughly 290,000 boe.
The results can be found in the table below:
(source: own calculations based on the ARs for 2013)
Liquids do not only mean classical oil, but also natural gas liquids - NGL.
Different Portfolios and Prices
Once again, there is a clear connection between realized price and percentage of liquids produced. In the case of the eight companies in this article it is nearly linear:
American Eagle could charge $86 for its boe (practically a real bbl), while Antero only realized $28 for its boe (or $4.64 for its 1,000 scf equivalent). As the oil and gas industry is de facto a price taker, the price boundary conditions for all companies active in this sector are the same. What is different for every company is its decision making, the quality of its reservoirs, the placement of its wells and its operational and administrative efficiency. All this factors influence the costs a company needs to produce one boe and therefore its pre-tax margins. This parameter differs widely for the eight enterprises in this article. Diamondback is the clear winner (more than 40%), followed by Cimarex. The other end of the spectrum is definitely Antero, for the reasons I have described earlier. Ignoring Antero's high stock based compensation, the company would have had costs of $24.78 per boe and a pre-tax margin of roughly 11%.
It is important to note that pure tight oil companies tend to be small sized (the biggest company in this article only had revenue of $2 billion - big for some industries, but rather tiny for an upstream company). As they cannot profit from the economies of scale, SG&A and interest costs tend to be very high. The perfect example for this is American Eagle: with its annual revenue of just $50 million it has SG&A and interest costs that exceed $25 per boe. On the other hand, its operational costs (costs of sales plus depreciation) are only about $45 per boe (practically per bbl of oil). Companies like American Eagle may therefore be very attractive takeover targets, especially in the times of low oil prices. Nevertheless, the company's shares did horrible on the stock market, when American Eagle had a high loss in 9M mostly due to early repayment of debt. However, deprecation also rose significantly on a boe basis. As I only skimmed the report, I am not sure whether this is only temporary or permanent. But it definitely emphasizes one fact: whenever one considers to invest in a company, it is necessary to investigate as many aspects as possible. Basing decisions only on production costs for one year alone is not very wise.
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