Summary
- The profit any oil company makes depends on the costs its needs to produce its goods.
- The oil price fall in 2014 led to high impairments in the industry, while many shale producers could profit from derivatives.
- Shale producer expanded their business (especially oil), but made less revenue per boe.
- Many of them could reduce their costs per boe. Remarkable is the decrease in SG&A expenses per boe.
Background
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, Niobara 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, basically the generation of artificial fractures. These 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 reactions 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.
The drop in the price of oil has fueled the debate about the actual production costs in tight oil plays. Estimates differ widely from source to source. Reuters offers a 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. Instead it focuses on the costs companies need the 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 emergence of a huge number of companies. Among the 121 upstream companies I have investigated for 2013 there are 37 tight oil companies. In 2014 some smaller companies were bought by bigger competitors (Athlon by Encana (NYSE:ECA) and Kodiak by Whiting (NYSE:WLL)) or merged (Forest with Sabine (OTCQB:SOGC)) and further consolidations are expected. In one of my last articles I already started my investigation about shale producers 2014’s production costs with companies that produced more than 40 million boe in 2014. In this article I investigate further 7 companies: Abraxas Petroleum (NASDAQ:AXAS), Approach Resources (NASDAQ:AREX), Bonanza Creek Energy (NYSE:BCEI), Callon Petroleum (NYSE:CPE), Carrizo Oil & Gas (NASDAQ:CRZO), Clayton William Energy (NYSE:CWEI) and Comstock Resources (NYSE:CRK).
Methodology
The key point for me is to catch the real production costs of hydrocarbons as accurate as possible. For that reason I only consider costs that are directly related to oil and gas production. As the upstream business is a pure commodity business, many companies have bought derivatives to hedge their sales. As gains or losses from that instruments are not directly related to production, I do not consider them directly in my method. Nevertheless, as they might have impact on the future of the company, I mention them if they are significantly high. The same is true for impairments.
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 $ 60 and the price for 1000 scf of gas is about $ 3. This means, revenue from 1 boe of oil is higher than revenue for 1 boe of gas ($ 60 versus $ 18). 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. ExxonMobil (NYSE:XOM) 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, Depletion and amortization, 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:
As I have noticed in one of my articles, that cash flow situation does not look well for the majors. In the long term, a profitable company must be able to generate enough cash flow to cover its capex and to buy money back to its shareholders (either via dividends or share buybacks). Therefore I included operating cash flow and total capex in my data. Operating cash flow and capital expenditure both refer to the whole company. Capital expenditure is investment in assets as well as in subsidiaries if they are not consolidated. This number does not include any subtractions because of the selling of assets. I also add the cash flow companies generated through sale of assets.
Application on 6 Shale Producers
I have applied my method to 7 North American shale producers. All of them I have already investigated in 2013, so now I can compare numbers. The results for 2014 can be found in the table below:
(click to enlarge)
(source: Annual Report 2014 if already published, otherwise company websites)
I have also used my methodology in the following articles:
- 2013’s Costs for 121 Companies
- Independents I
- Independents II
- Independents III
- Shale Oil Producers I
- Shale Gas Producer
- Oil Sands I
- Oil Sands II
Discussion
Before I discuss the results of this article, I would like to note that the fall in the oil and gas prices has led to a first big casualty: Quicksilver Resources (NYSE:KWK) has filed for bankruptcy. In one of my articles, I investigated the company’s 2013 results and calculated a negative pre-income tax margin of 26%. It was clear that a company with such a cost structure can’t survive for long.
Before the second half of 2014, no one ever questioned the huge economic potential of shale oil production. In accordance with this fact, among the 7 companies in this article, ot of them increased their production from 2013 to 2014, with Comstock being the only exception.
Abraxas increased its percentage of liquids produced by 10 points, and was therefore able to get a higher price per boe in 2014 than in 2013. But the company was also able to decrease its production costs per boe significantly, especially in terms of lifting costs, SG&A and interest expenses. Eventually, the company’s income margin rose to 28%, despite still high SG&A expenses of more than $ 6 per boe.
Approach increased its production by nearly 50%. With percentage of liquids produced roughly equal in 2013 and 2014, the company saw a small drop in realized revenue per boe. The reason for the relative low realized price is the high amount of NGLs Approach produces. Although they are considered to be liquid, the company could only realize $ 28.74 per barrel of NGL ($ 87.69 per bbl of oil). Production costs remained roughly the same between 2013 and 2014, decreases in SG&A were offset by higher financial expenses.
Bonanza’s percentage of liquids produced remained roughly the same, but the price the company could realize for its average boe fell. Nearly all categories of costs rose from 2013 to 2014 resulting in an increase of total costs of more than 10%. Needless to say, Bonanza’s profit margin fell from 30% to 13%. Other effects on the company’s balance sheet include $ 170 million impairment and $ 121 million gain on derivatives. Additionally, the company spend more than 200% of its operational cash flow for capital expenditure (with an increase in production of 45%).
Callon could rise its production by 88% from 2013 to 2014, the highest increase I have seen so far. Percentage of liquids got up from 54. 5% to 79%, but realized revenue rose only slightly. On the other hand, Callon did very well in reducing the company’s costs. Lifting costs went down by more than $ 2 per boe and depreciation by more than $ 3.5. Although SG&A expenses also fell, they are still extremely high with $ 12 per boe, reflecting Callon’s small size. With such a high value it is amazing that the company can achieve a pre-income tax margin of 19%. An additional item on the balance sheet were gains on derivatives of $ 32 million.
Carrizo is the next company that increased its liquid content significantly (18 points). This can also be seen in the rise in revenue per boe sold. It is remarkable that the company was able to decrease its average production costs from 2013 to 2014. Lifting costs are very low (less than $ 10 per boe). While depreciation per boe rose, Carrizo was able to reduce both SG&A and interest expenses significantly.
Clayton’s percentage of liquid produced remained roughly equal from to. However, revenue per boe fell by more than $ 4. Costs went also down, but did so less than revenues (both absolute and in terms of percentage). Exploration expenses more than doubled, but brought good results (a replacement of 405%). Interest expenses per boe are still very high, indicating high levels of debt. On the other hand, Clayton could fund 86% of its investments via operational cash flow and the sale of assets (a value well above average in the upstream industry).
Comstock had again a negative pre-tax operating margin. It even increased from minus 5% to minus 8%. While the company could increase its revenue per boe by 40% (due to a rise in percentage of liquids produced of 20 points), costs rose even faster. Because of the huge change in percentage of liquid production, it is a bit difficult to compare single costs items directly. Though, one thing is prominent: interest expenses per boe rose by nearly 50%, a sign of an increasing debt level.
Regarding the companies in this article, there is no clear trend in terms of pre-income tax margin. Some enterprises could increase it, while for others the opposite was the case. The same is true for interest expenses.
However, it was also possible to identify clear trends: higher total production and increase of percentage liquids produced was true for all of the companies. Additionally, all of them managed to bring their SG&A expenses down. This might partially be a follow of lower stock-market based compensation, as market capitalization of all upstream companies decreased in 2014.
Not one company in this article generated more cash from operations than it needed for its capital expenditure. All of them needed to borrow money from banks or via bonds to finance their investments or pay dividends. Nevertheless, as all of the shale producers in this article are growing, it might not be such a big problem, as long as they are growing. At least, as long as they keep their costs under control. If banks are still willing to lend money to oil producers at today’s price level, is still another question.
How Much Does It Cost To Produce One Barrel Of Oil From Shale (Abraxas ... - Seeking Alpha (registration)
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