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

I drilled my first Bakken horizontal well back in 1990.  We had so many problems with well bore integrity we gave up after drilling only a handful of wells.  In fact, we were getting cuttings the size of hockey pucks at the shale shaker.  Fast forward twenty years and the Bakken is the most successful horizontal oil play in the world.  We knew there was oil and gas in that shale we just didn't have the technology to get it out. 

Bakken economics compare favorably to other horizontal plays. The table below compiled by Stephen Berrman from Pritchard Capital Partners, LLC illustrates this fact.  Notice the Haynesville play has a higher Gross EUR (Estimated Ultimate Reserves) but the F&D (Finding and Development) cost is higher.  At a 10:1 (gas to oil) conversion the advantage of an oil shale play is seen in F&D costs that are almost half of the Barnett and Haynesville. 

 Mr. Berman also reveals in the next table that lower F&D costs are a result of operational advancements.   Well costs have nearly doubled since 2006 yet EUR has increased 5.5 times.  This is typical of a shale play as the operators start to figure out the play.  In this instance, it's both hydraulic fracture technology and using super extended laterals that account for increase in EURs.

Rising acreages costs are a direct result of the lowering of F&D costs.  Below you can see that from January 2008 costs were below $1000 per acre.  Late 2009 saw over a 6-fold increase of acreage costs exceeding $6.000 per acre.  As the economics of the play improve, the operators can afford to pay more for acreage.

The above tables and graphs provide an excellent example of how the economics change as operators climb the learning curve of a shale play.  Not all plays are as dramatic as the Bakken, but with perseverance and a smart technical team these types of results can be expected.  It took close to 15 years to figure out the Bakken using horizontal technology.  I wish I knew then what I know now.

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The economics of a shale play are sensitive to certain criteria that may not be critical to a conventional type oil or gas play.  One important criterion is the Initial Potential (IP) and the shape of the hyperbolic decline production curve.  A hyperbolic decline curve is composed of an IP followed by an initial steep decline rate, transitioning into a later long term, shallow, stabilized decline rate (see the graph below from Range Resources).  Shale production is characterizes by a steep decline curve early in its productive life.  The more oil and/or gas that you can make up front the better the economics.  

We've heard about the impressive IP's coming out of the Haynesville Shale and Marcellus Shale plays.  Currently, there is a lot of discussion about the initial decline rate of the Haynesville.  Analysis of current producing wells indicates that the wells are stabilizing in about one year.  This rapid decline calls into question some of the large reserves and the economics being proclaimed by the operators in the play.  Allen Brooks discusses this in his article:  New Research Questions Haynesville Shale Economics.

Obviously, costs and prices are also important criteria affecting the economics.  However, these two factors are known early on in a shale plays life.  Costs are determined by:

• Depth of target shale and length of lateral
• Number and size of stimulations
• Lease prices
• Existing infrastructure

Finally, price (especially for gas) can make or break a play.  Gas price depends on proximity to demand.  A big play driver for the Marcellus Shale is the price that producers get for their product.  The northeastern U.S. has the highest gas prices in the nation.  With the current price disparity between oil and gas, an oil shale play such as the Bakken has better economics than the Barnett Shale.  Due to the amount of reserves produced early in the wells life, the price on day one may determine if you drill or not.  Testament to this fact is the decline in activity in the Barnett over the last year.

Time will sort out the economics of all shale plays.  Watch the decline curves and hope for higher gas prices.

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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.

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