In oil and gas acquisitions, one of the most commonly used metrics is dollars paid per flowing barrel. Comp tables also often use this metric to compare company valuations and identify where value may be for future acquisitions.
Once an acquisition is made, the price paid per flowing barrel for those properties are almost immediately reflected in the stock price of junior oil and gas companies operating in the same areas. This is especially true for some of the newer tight oil plays where well results are not necessarily available to the public or analysts, making it difficult to run DCF models and determine values for the production. In the case of a planned arrangement, which is usually the manner for acquiring junior oil and gas companies or assets, the acquiring party will likely receive access to well data in order to determine a price they’d be willing to pay for the assets.
The basic valuation calcuation for an acquistion is based on two main things: producing reserves and undeveloped land. Of course, facilities may also add value, but for this post let’s just focus on the production and undeveloped reserves side of the equation.
Production is valued based on the engineering value of the assets. This is basically the expected net present value of the producing well, accounting for future production declines and discounting all of the future cash flows to a present value. I’ve heard that buyers are usually willing to pay 90-100% of the value of these assets. Of course there are a lot of variables involved in this calculation, including predicting production declines and commodity prices, but this production has little risk since the drilling has already been done and the well results are available. An acquiring company may see further value in such assets by applying EOR methods, or just lowering operating costs by consolidating production in the area. Assuming production of 1000 boepd valued at $75,000 per flowing barrel, that means the existing production may be worth in the neighbourhood of $75 MM.
Undeveloped land is also of value, but given that there is capital and risk involved in developing it, of course an acquirer is not willing to pay the full value. As an example, let’s say the seller has 20,000 acres of land of which 60% is prospective for drilling. This means the seller has around 19 sections of prospective lands (20,000 acres / 640 acres per section x 60%). Depending on the play and the commodity, the company may be able to drill anywhere between 1 and 16 wells per section. The basic principle behind downspacing (# of wells allowed on lands) is the government wants to ensure fields are efficiently depleted with as little environmental impact as possible and thus do not allow companies to over-drill lands. Fields that ‘communicate’ well through porous and permeable rock structures usually require fewer wells than fields where wells can only draw fluid from close to the bore hole. In any event, for our example let’s assume 8 wells per section, meaning the undeveloped lands hold around 152 potential drilling locations. Assuming the NPV of each well is $2 MM, this means the undeveloped lands could potentially be worth around $304 MM.
This would imply a total deal value of $379MM, or $379,000 per flowing boe ($75MM + $304MM / 1000 boepd). Of course, a company is not going to pay full value for undeveloped lands as it will take capital and time to drill and develop them, and there may be increased geologic risk. For this example, let’s assume the buyer and seller agree that the buyer will pay 30% for the undeveloped lands, making the total value of the deal $75 MM producing + $91MM undeveloped ($304MM x 30%) = $166 MM or $166,000 per flowing barrel.
Hopefully this basic tutorial helps you understand and recognize the potential value in undeveloped reserves, especially when monitoring juniors positioning themselves for takeover.
