The only time that the US saw a monopoly in the oil and gas industry was the time of Rockefeller's Standard Oil - SO. The company had a domestic market share of more than 90% at the end of the 19th century. It became so powerful that it was seen as a threat and in 1911 the United States Supreme Court ruled that it was an illegal monopoly. Standard Oil was ordered to break up into 90 independent companies. The biggest were SO of New Jersey (later known as Exxon) and SO of New York (later known as Mobil). Since then, the American upstream industry has been dominated by some huge companies with enormous capital and a large number of more flexible, smaller companies. With the increasing industrialization of the United States the country's oil demand rose and rose and so did the production. When in November 1970 total oil production peaked, as predicted by Hubbard in 1956, many saw this as proof for his peak oil theory.
Nevertheless, Hubbard did not take technical improvement and unconventional resources into account. When in the early 2000s technical progress was sufficient to develop tight oil reservoirs, production started to rise again. But despite the tight oil surge, conventional production still happens today in the US.
After investigating 2013 costs for 121 companies, I continue my investigations for 2014. Up to now I have investigated production costs of many US upstream companies, from majors to the big independents and shale producers. In this article I focus on smaller US companies that get some of their production from conventional sources. In this article, 6 companies are included: Breitburn Energy (BBEP), Concho Resources (NYSE:CXO), Denbury Resources (NYSE:DNR), Evolution Petroleum (NYSEMKT:EPM), MDU Resources (NYSE:MDU) and Midstates Petroleum (NYSE:MPO).
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. 6,000 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, 6,000 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 1,000 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 US companies
I have already investigated the companies in this article last year, with the only exception being Evolution. Evolution is a tiny Houston-based company that focuses on the development of incremental hydrocarbons within brown fields (enhanced oil recovery - EOR). The enterprise's main asset is located in the Delhi field in Louisiana where Evolution is running a CO2-EOR project.
The results for 2014 can be found in the table below:
(source: own calculations based on the ARs for 2014)
Liquids do not only mean classical oil, but also natural gas liquids - NGL.
I have also applied my methodology in the following articles. The results may serve for the purpose of comparison.
- 2013's Costs for 121 Companies
- Independents I
- Independents II
- Independents III
- Shale Oil Producers I
- Shale Gas Producers
- Oil Sand Producer I
- Oil Sand Prodicer II
- Shale Oil Producers II
- Shale Oil Producers III
- Shale Oil Producers IV
- Shale Oil Producers V
2014 saw a drop in the oil price of more than 50%. However, capex budgets for that period were decided earlier, in a high price environment. It is therefore no wonder, that practically all companies could increase their production.
Breitburn increased its production to nearly 14 million boe, but could rise its percentage of liquids produced by 20 points. However, realized price per boe rose only by $1, while Breitburn made $566 million on derivatives. On the other hand, total costs rose by a much higher percentage. Troubling is especially the strong increase in interest expenses that are now responsible for nearly 15% of all costs. Eventually, pre-income tax margin became slightly negative. Breitburn also wrote-off $149 million impairment.
Concho increased its percentage of liquids produced only slightly and therefore suffered a reduction in its realized revenue per boe. Due to a high increase in cost of sales, total production costs increased. Eventually, pre-income margin went down from 28% to 16%. Concho had to impair $447 million, but gained $890 million on derivatives.
Denbury's status as a mere oil producers did not change from 2013 to 2014 and production remained roughly flat. Nevertheless, the fall in the oil price hit the company relatively hard, as average realized revenue fell by more than $6 per boe. On the other hand, costs rose slightly. While Denbury was able to reduce costs of sales, both SG&A and interest expenses rose (the latter by 30%). The company is one of the few in the upstream sector that was able to fund its capital expenditure with cash flow from operating activities. Additionally, the company made $555 million on derivatives and paid $133 million for the early extinguishment of debt.
Evolutions' data for this article only refer to the second half of 2014. In this period the company only produced 0.35 million boe, practically only liquids. Despite extremely high SG&A expenses (26% of revenue), other costs were low enough that Evolution could achieve a pre-income tax margin of 35%. Helpful was, that the company has de facto no debts.
MDU increased its percentage of liquids produced from 2013 to 2014 by more than 15 points. Production fell slightly. However, due to the fall in the oil price, revenues per boe rose to a lesser extent. Costs rose over all categories, whereby MDU could profit from its conglomerate structure in terms of financial expenses. Eventually, the company had a pre-income tax margin of 23%. Additional positions on the income statement were gains on derivatives of $32 million.
Midstates' percentage of liquids produced remained nearly the same from 2013 to 2014. Therefore the company saw a decrease in realized revenue per boe. While total costs went down a bit, the company spend nearly 24% of its total costs for the payment of interest, not a very reassuring fact. It comes not surprising the company's stock price went down 78% over the last year. Midstates made $139 millions on derivatives and had to impair $86 million in 2014.
Overall, smaller US companies are more diverse than homogeneous groups like shale producers. General trend are an increase in total production, a higher percentage in percentage of liquids produced and a decline in the pre-income tax margin of nearly all companies. The first two trends are also true for shale producers, but not the last. It seems, that conventional oil producers have less potential for costs savings than shale producers have.
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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.
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