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 gas-bearing shales and the gas in it is called shale gas. The most known gas shales in the US are the Marcellus shale, the Barnett shale, the Haynesville shale and the Fayetteville shale. 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.
The shale gas revolution started in the mid-2000s in the US. After decades of research, technology (i.e. the combination of fracking with horizontal wells) was finally able to produce gas from shale economically. Production soared and its rise led to a dramatic fall in North American gas prices. Still, the US is the only country in the world with significant gas production from shale, although potential is evaluated in a number of other regions.
Oil is hardly ever produced as pure liquid. Normally it comes as a mixture with natural gas and gas condensate. Hence, it does not make much sense to apply costs to the production of oil or gas alone. To deal with this issue the concept of barrel oil equivalent - boe - has been conceived. 6000 cubic feet of gas at standard conditions is about one boe. All costs mentioned below refer to one boe, meaning these 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 overestimate the costs of gas production.
In this article, I investigate production costs for shale gas producers. It is hard to define an exact boundary between oil and gas producers. One might define any company that produces more than 50% gas in terms of barrel oil equivalent as a 'gas producer'. The problem with this definition is revenue. One boe consisting of gas gets much less money than a barrel consisting of oil. Hence, it might be that a company that produces 50% oil gets 75% of its revenue from oil. It is misleading to call such a company a 'gas company'. Eventually, I drew the line between gas and oil producers at 25% percentage of liquid produced. The shale gas companies investigated in this article are: Antero Resources (NYSE:AR), Cabot Oil & Gas (NYSE:COG), EQT Corporation (NYSE:EQT), EXCO Resources (NYSE:XCO), Ultra Petroleum (NASDAQ:UPL) and WPX Energy (NYSE:WPX).
The key point for me is to catch the real production costs of hydrocarbons as accurately 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 these instruments are not directly related to production, I do not consider them directly in my method. Nevertheless, as they might have an impact on the future of the company, I mention them if they are significantly high. The same is true for impairments.
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 (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 models 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 noted in one of my articles, 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 Gas Producers
I have applied my method to 6 major North American shale gas producers. 5 of them I have already investigated in 2013, so now I can compare numbers. The only newcomer is Ultra Petroleum. The company is active in two basins across the USA: the Green River Basin and the Appalachian Basin. Ultra started in 1997 with operations in the Pinedale and the Jonah Field and is currently in the development stage in the Marcellus shale and in the Uinta Basin.
The results for 2014 can be found in the table below:
(source: Annual Report 2014 if already published, otherwise company websites)
I have also used my methodology in the following articles:
- 121 Companies 2013 (contains links to individual articles)
- Independents I (APC, APA, DVN, EOG)
- Independents II (CHK, ECA, HES, OTCQB:MARA)
- Independents III (NBL, OXY, SWN, TLM)
- Shale Oil Producers I (XEC, CLR, LINE, PXD, SM, WLL)
Antero's pre-income tax margin increased dramatically from 2013 to 2014. This happened although realized revenue per boe fell by $5. But Antero was able to decrease its cost significantly. Main contributor to this effect was the fall in SG&A expenses as in 2014 stock-based compensation reached a normal level again. But Antero did also well with regards to lifting costs and depreciation, resulting in a pre-income tax margin of 16%. Additionally, the company made $470 million on derivatives in 2014.
Cabot raised its production by nearly 30% from 2013 to 2014. Its percentage of liquids produced remained roughly equal. The company saw a small decrease in both its realized sales per boe and the cost it needed for the production of 1 boe. The reduction in SG&A is mainly responsible for the fall in total costs. Pre-income tax margin is practically the same for 2013 and 2014. This positive operating result was offset by impairments of $770 million. Cabot gained $200 million on derivatives in 2013.
EQT raised both its production and the percentage of liquids produced from 2013 to 2014. Nevertheless, realized revenue per boe produced and sold rose only slightly. Contrary to the other companies, EQT increased the SG&A expenses per boe by nearly $1. The pre-income tax margin fell from 2013 to 2014.
EXCO's production fell from 2013 to 2014 by roughly 18%, but the percentage of liquids the company produced rose by 5%. This resulted in a much higher revenue per boe produced, but costs rose also across nearly all categories. EXCO could increase its pre-income tax margin from 2% in 2013 to 5% in 2014. Additionally, the company gained $88 million on derivatives.
Ultra Petroleum had a successful year in 2014. At 92% gas produced, it realized about 80% of its revenue from gas sales. Lifting costs and depreciation were both quite low. Financial costs were relatively high with more than $3 per boe. Ultra could realize a price of more than $29 per boe at costs of only $19.2. This resulted in a high pre-income tax margin of more than 35%. Additionally, Ultra booked gain on derivatives of more than $126 million in 2014, but did not impair assets.
WPX decreased its production from 2013 to 2014 due to asset sales, but could increase its percentage of liquids produced. Actually, its oil production rose by 56%. It also increased its realized revenue per boe significantly. The company was also able to reduce its costs, but it did so from a very high level. Although there was significant improvement in the pre-income tax margin, WPX still remained in the reds operationally. The company made $434 million on derivatives, but also had to book a loss of $196 million on the assets it sold.
The fall in gas prices in 2014 was less dramatic than the fall in the oil price. The North American shale gas producers are still profitable operationally at the current price level. One problem is the huge amount of debt some companies carry, seen in the high interest expense per boe. Extra profit for most shale producers was added by gains on derivatives in 2014, but this will most likely be a one-year effect. Some of the companies already booked significant impairments, while others might follow soon. As observed in my other articles, the upstream industry has a cash flow problem. This is also true for the shale gas producers in this article. Not one company generated enough cash flow from operations to fund its necessary investment. Only EXCO generated enough money from the sale of assets to finance the difference. But it did so for the price of lower production.
It might be that the situation in the gas market a couple of years ago gives us a proxy for the effects of the oil price fall on tight oil producers.
Disclosure: The author has no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.
The author wrote this article themselves, and it expresses their own opinions. The author is not receiving compensation for it (other than from Seeking Alpha). The author has no business relationship with any company whose stock is mentioned in this article.