I wanted to initially discuss a few of the valuation metrics that can be used to compare Exploration and Production companies. I'm sure my views will evolve over time, but this is my thinking going into this project:
EV/EBITDA- Or total enterprise value divided by Earnings Before Interest Taxes Depreciation and Amortization is probably the most useful and most general valuation marker. This metric accounts allows the comparison of two companies with very different levels of debt, and different production mix, on a fairly apples to apples basis. Certainly companies with different growth profiles and different capital efficiency may deserve very different EV/EBITDA valuations, but it is still a very useful metric.
EV/P1 reserves- This or an adjusted version of this where gas reserves are discounted by perhaps 66%, and natural gas liquids are discounted by 50% versus oil may be useful. There are a number of issues that we should be aware of with this metric though. One big problem is the large differences between proved-developed-producing (PDP) reserves and undeveloped (PUD) reserves. Because of the more capital intensive nature of shale gas and tight oil production, the difference between developed (ie with wells producing oil) and undeveloped (ie they have proved that the oil is there to the satisfaction of auditors, but have yet to drill the wells to take it out) is much more significant than in decades past, where the main difficulty lay in finding the oil rather than extracting it.
Another problem with reserve based metrics is that reserves today may be more vulnerable to being reclassified now than in years past. When the price of gas went down undeveloped reserves were dramatically revised by companies like Exco and others in higher cost areas like the Haynesville Shale. The SEC requires that companies intend to bring undeveloped reserves onto production within five years, and do so at a profit, otherwise they cannot count them as proved (P1) reserves. Similar revisions would happen in the tight oil plays like the Bakken, Eagleford, or Permian if the price of oil were to decline dramatically.
The classification of oil sands as proved reserves, starting in 2010 under SEC rules, also makes this metric a bit more complicated. As with tight oil, the main cost is associated with extraction and processing, not with locating the oil. If the price of oil went down significantly, the oil sands would no longer be reserves. Even if the price didn't go down, a barrel of oil sands in the ground is worth tremendously less than a barrel of oil in a proved-developed-producing conventional reservoir, in terms of the financial benefit it will provide to the company that owns it.
EV/daily production- This is another resource based metric that has some similar problems to the EV/P1 reserves metric, although it doesn't have the problems associated with developed vs undeveloped reserves. I also would recommend adjusting this to discount lower value NGLs and gas versus oil.
NAV- or "net asset value". This is a method favored by many sell-side analysts. It basically is a free cash flow model. The problem is that the moving pieces in an E&P company are so incredibly complex that it is fairly hopeless to create a model like this that provides any sort of reasonable prediction of the future. Take a company operating in the Bakken and imagine all the scenarios that could drastically alter the future potential of the company. Well designs could change and favorably improve well cost or recovery (as it has over the past year or so). The Bakken discount could change dramatically (as it has repeatedly). Service costs could dramatically change. The price of Brent or WTI could go up or down. Free cash flow models have always been notoriously inaccurate because a slight change in the discount rate and "terminal growth rate" of the company used in the model can cause a huge change to the valuation. A large part of the value is based on factors that are nearly impossible to predict. The only time when the FCF model can be quite accurate is in periods of high interest rate, where the value of earnings in the distant future is so heavily discounted that it has limited impact on the valuation. This is not the case at present, with our very low rates, and the uncertainties inherent in FCF models are magnified for an E&P company, making the methodology not very useful. I don't have access to the sell-side models, and in general will not be attempting to create NAV models myself.
I intend to concentrate on comparing one company to another, and not trying to decide whether E&P companies are a good value vs the rest of the market, which is in many ways a more difficult question.
EV/EBITDA- Or total enterprise value divided by Earnings Before Interest Taxes Depreciation and Amortization is probably the most useful and most general valuation marker. This metric accounts allows the comparison of two companies with very different levels of debt, and different production mix, on a fairly apples to apples basis. Certainly companies with different growth profiles and different capital efficiency may deserve very different EV/EBITDA valuations, but it is still a very useful metric.
EV/P1 reserves- This or an adjusted version of this where gas reserves are discounted by perhaps 66%, and natural gas liquids are discounted by 50% versus oil may be useful. There are a number of issues that we should be aware of with this metric though. One big problem is the large differences between proved-developed-producing (PDP) reserves and undeveloped (PUD) reserves. Because of the more capital intensive nature of shale gas and tight oil production, the difference between developed (ie with wells producing oil) and undeveloped (ie they have proved that the oil is there to the satisfaction of auditors, but have yet to drill the wells to take it out) is much more significant than in decades past, where the main difficulty lay in finding the oil rather than extracting it.
Another problem with reserve based metrics is that reserves today may be more vulnerable to being reclassified now than in years past. When the price of gas went down undeveloped reserves were dramatically revised by companies like Exco and others in higher cost areas like the Haynesville Shale. The SEC requires that companies intend to bring undeveloped reserves onto production within five years, and do so at a profit, otherwise they cannot count them as proved (P1) reserves. Similar revisions would happen in the tight oil plays like the Bakken, Eagleford, or Permian if the price of oil were to decline dramatically.
The classification of oil sands as proved reserves, starting in 2010 under SEC rules, also makes this metric a bit more complicated. As with tight oil, the main cost is associated with extraction and processing, not with locating the oil. If the price of oil went down significantly, the oil sands would no longer be reserves. Even if the price didn't go down, a barrel of oil sands in the ground is worth tremendously less than a barrel of oil in a proved-developed-producing conventional reservoir, in terms of the financial benefit it will provide to the company that owns it.
EV/daily production- This is another resource based metric that has some similar problems to the EV/P1 reserves metric, although it doesn't have the problems associated with developed vs undeveloped reserves. I also would recommend adjusting this to discount lower value NGLs and gas versus oil.
NAV- or "net asset value". This is a method favored by many sell-side analysts. It basically is a free cash flow model. The problem is that the moving pieces in an E&P company are so incredibly complex that it is fairly hopeless to create a model like this that provides any sort of reasonable prediction of the future. Take a company operating in the Bakken and imagine all the scenarios that could drastically alter the future potential of the company. Well designs could change and favorably improve well cost or recovery (as it has over the past year or so). The Bakken discount could change dramatically (as it has repeatedly). Service costs could dramatically change. The price of Brent or WTI could go up or down. Free cash flow models have always been notoriously inaccurate because a slight change in the discount rate and "terminal growth rate" of the company used in the model can cause a huge change to the valuation. A large part of the value is based on factors that are nearly impossible to predict. The only time when the FCF model can be quite accurate is in periods of high interest rate, where the value of earnings in the distant future is so heavily discounted that it has limited impact on the valuation. This is not the case at present, with our very low rates, and the uncertainties inherent in FCF models are magnified for an E&P company, making the methodology not very useful. I don't have access to the sell-side models, and in general will not be attempting to create NAV models myself.
I intend to concentrate on comparing one company to another, and not trying to decide whether E&P companies are a good value vs the rest of the market, which is in many ways a more difficult question.
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