The fall in the oil price was one of the most significant economic developments of the last year. As a result investments were slashed, tens of thousands of jobs were cut and the North American rig count more than halved. Some weaker companies already went bankrupt and more are expected to follow. In this article I want to focus on some of the world's biggest oil producers and how the price slump has affected them. I start with some comments on their income statements for Q2 2014. Then oil production costs per boe for Q2 and 6M 2015 are calculated (the numbers for 2014 and 2013 may serve as comparison). The article finishes with measures of cost cutting and remarks about the sustainability of the upstream industry.
BP (NYSE:BP) reported an accounting loss of $5,823 million for Q2 2015. However, this number includes inventory holding gains as well as $7,579 million of unfavourable impact of non-operating items (mostly due to agreements in connection with the Deepwater Horizon disaster). BP considers its underlying replacement cost profit (URC) to be a more realistic assessment of its earning power. This value amounted to a profit of $1,313 million in Q2 (after $2,577 million in Q1 and $3,365 million in Q2 2014). BP has two divisions that are related to oil and gas production: the first one it its classical upstream business with BP's subsidiaries and the second one is Rosneft, where BP holds 19.75%. BP achieved in Q2 an URC profit of $494 million in its upstream division and an URC profit of $510 million in Rosneft. Both values are before interest and tax.
ConocoPhillips (NYSE:COP) reported a loss of $179 million for the second quarter of 2015. As ConocoPhillips is only active in the upstream business, this is also the result for its oil and gas producing business. The company made a profit of $2,081 million in Q2 2014 and a profit of $272 million in the first quarter of this year (although this is mainly related to an income tax benefit, operationally the first quarter was negative too).
Exxon Mobil (NYSE:XOM) reported a profit of $4,190 million for the second quarter of 2015, down from $8,780 for the same period in 2014. The upstream segment made a profit of $2,031 million (completely attributed to non-US), down from $7,881 million one year before. Production increased by 3.6%, while liquid production increased 11.9% (!) year-over-year.
Shell (NYSE:RDS.A) reported a profit of $3,986 million for Q2 2015. The company's upstream segment reported a profit of $774 million ($2,539 million in Q1 and $3,820 million in Q2 2014). However, when identified items are excluded, the earnings were $1,037 million in Q2 ($675 million in Q1 and $4,722 million in Q2 2014). In the last quarter, those identified items referred mainly to divestment gains, change in value of derivatives and a statuary tax rate change in Canada. Significant is the decline in production volume (2,731 kboepd in Q2 versus 3,077 kboepd for the same period one year ago). This can be mainly attributed to 18% decrease in natural gas production, but liquid production also declined. While operational cash flow from upstream segment was $2,092 million, upstream investment in the second quarter amounted to $5,916 million.
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, 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 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.
There are two basic principles for the accounting of upstream costs: (1) successful effort - SE - accounting and (2) full cost - FC -accounting. Successful effort accounting results in four regular categories in the income statement (exploration expenses, production expense, non-income related taxes and DD&A) plus impairments. Full cost accounting does not include exploration expenses, but results otherwise in the same categories. Practically all majors use SE.
Exploration expenses only occur when the SE method is used. While costs for exploration wells are capitalized (exploration assets), other exploration-related costs (e.g. seismic studies) are directly expensed. If the wells lead to the discovery of proved reserves, assets are reclassified; otherwise they are expensed as exploration costs. FC companies capitalize exploration expenses as they incur.
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. Lifting expenses are the easiest type for accountants. In both methods they are expensed as incurred.
Non-income related taxes refer to all payments that governments or the owner of the resources receive (i.e. severance and production taxes, royalties). The amount and nature of these payments vary significantly from country to country.
DD&A is very similar to the one that occurs in other industries.
Oil producers also have overhead costs, especially costs related to SG&A and financial costs. 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 estimate SG&A for E&P. I did the same for any similar type of cost (marketing expenses, R&D) and for financial expenses.
Because of the difference in the used accounting method and the non-income related taxes scheme some cost categories between companies may not be directly comparable.
The cash flow perspective can provide an additional inside on the state of a company. Cash flows from operating activities refer to cash flows before change in working capital. Capital expenditure only refers to real investments, either directly or in associates and joint ventures.
Production costs for Q2 and 6M 2015
(source: own calculations based on company statements/Q-10s)
BP's exploration expenses include an impairment of $432 million as the company declared force majeure in Libya. As the company does not state any details about its share in Rosneft, the numbers in the table refer only to its upstream division. For some companies no detailed information about segments were available. To get an estimate for certain cost types, I multiplied total company costs for a certain category (e.g. DD&A) with the percentage of this cost type that was used for the upstream segment in 2014.
Overall, depressing results. Exxon Mobile was the most profitable company in Q2 with a pre-income tax margin of 8%, closely followed by Shell with a margin of 7%. This pattern is also in line with decreases in the company's stock prices (from the 2014 maximum); XOM did best, while COP (negative profitability in Q2) did worst.
Job and Capex Cuts, but Constant Dividends
The majors are reacting. A second round of layoffs has already started and this time it is more focused on E&P companies. Of the 150,000 layoffs that took place across the oil and gas industry since last fall, only about 10 percent were related to producers, while more than 100,000 jobs were eliminated from service and drilling contractors. Many E&P companies thought that the decrease in the oil price is only temporary and they did not want to lose their skilled workforce. But now things seem to change. Many majors are catching up and announcing massive job cuts: Chevron 1,500, Shell 6,500 and ConocoPhillips noted that it already has reduced its work force by 1,500 and expects to continue so.
There might also be a second round of capex slashing. ConocoPhillips was the first major that reduced capex after prices fell. Recently, it reduced its investment by another $0.5 billion.
On the other hand, all majors are committed to keep their dividends steady. Shell's dividend will remain unchanged at $1.88 and the company wants to pay at least the same amount in 2016. BP's CEO also stated that his first priority is maintaining the dividend.
At current oil prices even majors can't make much money. Q2 saw an average Brent price of $61.92 per barrel and an average WTI price of $57.84, both significantly higher than the current oil price level. Jobs and capex cuts are therefore no wonder. Most likely, these measures will result in lower production costs per boe. However, how far these efforts can go is questionable and if the oil price keeps at present level, majors can only maintain their dividends by selling assets or raising debt, both not very sustainable strategies. E.g., let's take Exxon Mobil, arguably the best in class, as mentioned above. The company paid back $4.1 billion to its shareholders in Q1, but did this by increasing debt by $1 billion. If the oil price does not recover, this quarter Exxon Mobil needs to raise more debt or sell more assets if it wants to maintain dividends and share buybacks. Something similar is true for the other companies in this article.
One should not forget that the majors (except ConocoPhillips) can rely on their downstream business that is thriving amid the current price environment (low gas prices drive demand, while refining capacity did not change). Other, independent companies don't have that luxury. As can be seen from my investigations about 2013 and 2014 production costs, their margins are also smaller. Presently, many smaller upstream companies are spending more to produce one boe than they are realizing for it. An oil price at the current level - or even the level of Q2 - is not sustainable at today's cost level. The big questions is to what extent producers can slash their expenses.
Disclosure: I/we have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.
I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.