Oil and Gas Evaluation Report : Oil & Gas Evaluation Professionals : Obsidian Energy Company : · Seismic Interpretation, Petroleum Engineering

In a recent article, Keith Schaefer asks the question whether there should be standardized rules for reporting IP (Initial Production) rates for newly drilled wells.  As Keith points out, currently there is no standardized methodology for these reported tests and some operators choose to report instantaneous rates while others report average rates over some period of time; however, even these average rates are not consistently reported (24 hrs, a week, a month, etc.).

This is even more critical when looking at horizontal wells drilled in tight formations, which are typically frac'd on completion-- shale plays.  These characteristics typically create linear flow near the well and expose a large amount of "virgin" reservoir, both of which give rise to high initial rates which rapidly drop-off before stabilizing at a lower rate.

The IP rate of a new well can impact the economics of the well because the greater the initial rate the more revenue the operator can use to repay the development costs, which directly impacts the ROR (rate of return).  The IP alone, however, has little impact on the well's ultimate reserves which is the key to the project's economics.

When determining the well's ultimate recovery, what happens after the IP is more important than the IP itself.  The initial decline rate of the well and the hyperbolic exponent (the rate at which the decline rate lessens) give character to the production curve and ultimately determine the well's reserves.

When I read a press release which includes IPs it's usually with a great deal of skepticism.  The only thing you can tell for sure from an IP test is that the well isn't dry.  Only after several wells have been on production in a given area and a "type curve"  established, can the IP rate be used to approximate reserves.

There are several stories in the oil patch about the company who drills a well and based on it's IP, constructs a flowline, production facilities, and stakes several more offset wells (no doubt booking them as PUDs) only to have the well fizzle when put on production.  As bad as it would be to be the engineer on a project like this, it would be worse for the investor.

So, as Keith says, when it comes to reported IPs Caveat Emptor.

• Email This
• Print
• Comments
• Trackbacks
• Share Link

I read an article recently about Barnett leasing in Tarrant Co.  The question many landowners have is:  What constitutes a good deal?  Specifically, should I accept a larger bonus (money up front) or a larger royalty payment (a share of future production)? 

To answer this question you need to consider both sides of the deal.  First, what can the operator pay and still get a reasonable Rate of Return (ROR)?  Second, how does the future cash flow adjusted for inflation vary relative to the royalty interest?  To illustrate the ying and yang of a Barnett leasing we ran economics for an average Barnett Shale well in and around the core area.  We then created graphs to illustrate the economics from both the operator's perspective and the landowner's perspective.  The economic variables are royalty interest and bonus money.

The constants are:

• 2.65 BCFG of reserves
• 1.5 MMCFD first 30 days of production
• 3.5 MM$ to drill and complete
• $5.75 (1st yr), $6.00 (2nd yr), $6.50 flat for remainder of life gas prices
• 80 acre production unit

One of the important economic hurdles for the operator is ROR.  The graph illustrates ROR vs. Royalty %.  Although ROR requirements vary from company to company, anything below an unrisked 20% ROR is difficult for a company to swallow.  That being said, notice how bonus money and royalty affects the companies ROR.  At a 25% royalty and a $5,000 dollar per acre bonus, the company is right at the  20% ROR.   At a 20% royalty a company can afford a higher bonus of $8,000 per acre.  It's important to note that a bonus greater than $8,000 throws the ROR below the 20% ROR line.  A $30,000 per acre bonus with a 25% royalty results in a ROR around 8%.

Now let's look at the deal from the landowner (royalty) owner point of view.  As a royalty owner you are concerned with bonus money (money up front) and future cash flow from production.  This future cash flow must be adjusted for inflation because money is worth more today than at some future time.  We assumed a 4% constant rate of inflation throughout the life of the well.  The value of this cash flow today is represented by Present Value at 4% (PV4%) of one acre.  The purpose of the graph below is to illustrate how value is affected by royalty and bonus money.  For example, a  royalty of 20% combined with a $5,000 bonus is close to the same value as a 25% royalty combined with no bonus.  Again, the Y-axis on the graph represents the value of one acre in the 80-acre production unit. 

The point I want to make is that at present gas prices the days of $30,000 per acre bonus money that we saw in early 2008 is not realistic when considering the economics of a Barnett Shale gas well.  As gas prices increase the economics can bear a larger bonus, until then, expectations need to be lower.  Also, the economics parameters I used are for an average well over several counties.  Geographically specific areas may possess better or worse economics.  Gene Powell of the Powell Barnett Shale Newsletter does an excellent job of looking at revenue estimates for neighborhood in Tarrant County.

• Email This
• Print
• Comments
• Trackbacks
• Share Link

Volumes of oil and gas that have been discovered, but yet to be produced are referred to as reserves*.  One barrel in the ground is not necessary equal in value to another.  In an earlier entry I discussed the hazards of using simple yardsticks such as $ per barrel in the ground as a means of valuing an asset, and this is why. 

Risk is the main differentiating factor between the types of reserve categories and their associated values.  SPE (Society of Petroleum Engineers) categorizes reserves as follows:

• Proved
• Probable
• Possible
• Contingent Resources (not actually a reserve category since a contingent resource doesn't meet the criteria of a reserve)

The above list is in order of increasing risk, or decreasing chance of occurrence.  Since the value of an asset is a function of it's projected future cash flow, the lower the chance of occurrence (actual production) the less valuable the barrel.  So this list is also in order of decreasing value to the investor.

Proved reserves are considered to have reasonable certainty or a high degree of confidence of being recovered.  Often this is determined by a 90% probability of occurrence (P90).  Probable reserves are less certain than Proved, and Possible are even less than Probable. Probable reserves are often referred to in combination with Proved reserves as Proved + Probable (or 2P), and typically represent a 50% probability of occurrence (2P=P50).  In other words, we have an equal chance of recovering more, or less, barrels than our Proved plus Probable reserves.  Possible reserves when added to the Proved + Probable reserves make up what is referred to as 3P reserves, and these represent only a 10% probability of occurrence (P10).  So you can understand the investor's attraction to Proved reserves, and to a lesser extent Probable reserves, and often skepticism of Possible reserves.

When evaluating an asset we break these categories down further into their stages of development..  The Proved category is broken down into:

• Proved Developed Producing (PDP)
• Proved Developed Non-Producing (PDNP)
• Proved Un-Developed (PUD)

This list is again in order of increasing risk and decreasing value to the investor.  While all three of these categories are Proved reserves, and therefore have a high degree of confidence, there is increasing risk of occurrence and decreasing value simply due to their degree of development.  PDP reserves are already developed and are currently being produced, while PDNP reserves have had most of the capital necessary to develop spent, but are not currently producing and may require some additional capital to get producing, or may be waiting for a future event to occur before they can be produced.  The PUD category typically represents future drill wells where significant capital must be spent to recover these reserves which makes them less valuable compared to reserves that have already been developed.

The degree to which an investor is willing to pay for these different reserve categories varies widely and is determined by the risk tolerance of the individual investor.  It is very important for any investor to understand the risks associated with the reserves they are buying and to rely on an experienced and trusted evaluator to determine the associated risks.

* This of course is an over simplification and not all hydrocarbons in the ground meet the criteria to be called "Reserves."  For a more detailed discussion please refer to the SPE PMRS definitions.  Natural gas is often referred to in terms of barrels of oil equivalent, BOE, and the conversion is 6 MCF of gas = 1 BOE

• Email This
• Print
• Comments
• Trackbacks
• Share Link

The recent update of Newfield Exploration Co. Woodford Shale operations cites the use of Super extended lateral (SXL) completions has reduced drill and complete cost while adding incremental reserves. A SXL is a completion with a lateral length greater than 5,000 feet.

When we looked at the Barnett, another shale play, we see a direct correlation between lateral length and ultimate reserves. This is not a big surprise because your exposing more of the reservoir to the well bore. The economics are further enhanced because you only have to drill a single vertical portion of your well to exploit 10,000 feet of shale.

Where as, if you drilled 2 horizontal wells with a 5,000 foot lateral each you would have to pay for 2 vertical portionsto reach your objective.  Both scenarios expose the same amount of shale to the well bore, but the second scenario costs more.  That's the beauty of a SXL. The same reserves at a lower cost.  Newfield reports a $1,000,000 savings when drilling a 10,000 foot lateral vs, two 5,000 foot laterals.

The economic advantages of the SXL can only be realized when you have a contiguous acreage position, or regulatory system that allows placement of a long lateral. The majority of leases or units will not be able to support a SXL.  Many states are realizing the benefits to creating a regulatory system that lets companies pool varied interests to form drilling and production units where longer lateral technology can be applied..

When considering SXL completions it is important to note that the cost of mechanical failure rises.  This risk varies from play to play but it must be considered.  A second risk involves completion of the well bore.  Fracing into a fault or a karst that is a conduit to water could endanger production from the entire well bore.  A SXL As all shale plays develop, the SXL completions will continue to become more popular because the economics depend on it.

• Email This
• Print
• Comments
• Trackbacks
• Share Link