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

Rune Likvern has a very interesting article on The Oil Drum: Europe concerning OPEC's surplus capacity, how long it's likely to last, and the potential impact of oil prices. 

For those of us who are in the energy A&D business predicting the future of oil and gas prices is both very important and yet next to impossible to get correct.  The information reported in this article can help support a bullish outlook for oil prices in the near term despite the relatively flat NYMEX strip.

"Based on this analysis, it is probable that demand for OPEC supplies could grow by approximately 2 Mb/d between 2010 and the end of 2011. Putting the estimated current OPEC spare capacity of 2 Mb/d together with the expected increase in demand for OPEC oil supplies of 2 Mb/d suggests that during 2011, OPEC's spare capacity may be completely eroded--a very serious situation."

Read the entire article here

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When gas prices are high so is activity in the Rocky mountain basins.  When gas prices drop activity and excitement subsequently drop in the western half of the U.S.  This is primarily due to the low BTU content of most Rocky Mountain gas and its distance from U.S. markets.  The Bakken thrives because it's an oil play. 

In April, EOG announced that a successful horizontal well was drilled in northern Colorado that has produced an average of 555 barrels of oil per day.  This production is from the Niobrara Shale.  The Jake 2-01H is located in Weld County in the Denver-Julesburg Basin.  At a depth around 7,000 feet this would compare favorably to the Bakken if reserve size are similar.  Since the discovery EOG has leased more than 400,000 acres in northern Colorado and southern Wyoming.  Furthermore, other players such as Anadarko, MDU resources, St. Mary Land & Exploration, Chesapeake, and others have also amassed sizable acreage positions.

The importance of this find is that the Niobrara is present in 5 western states.  So the reserve volume could be huge as well as the economic impact to the Rocky Mountain states and the U.S. in general.  We'll continue to watch production and other activity to see if the Niobrara is a close relative or a distant pretender to the Bakken.

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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 concept of portfolio diversification has been a widely accepted method for reducing uncertainty (risk) in financial markets since Harry Markowitz's work in the 1950s.  In fact, one of the reasons financial institutions like oil and gas investments is, in part, due to the concept of portfolio optimization and the affect direct investment in these commodities has on their overall portfolio.  In general, oil companies, however, have been less receptive to implementing these concepts.

First some basic portfolio optimization concepts.  The basic idea is that while individual investments (properties, projects, etc) have their own unique set of parameters (ENPV-estimated net present value, risk, etc), when you combine these investments into a portfolio the interaction of these individual investments can alter the risk of the portfolio.  This is best demonstrated by an example used in Ball & Savage Associates 1999 paper where you have $10MM to invest and two distinct projects to choose from.  The first is a relatively "safe" investment and the second is relatively "risky," but the estimated NPV is the same for each.

ENPV(safe) = 60% * $50 + 40% * (-$10) = $26MM

ENPV(risky) = 40% * $80 + 60% * (-$10) = $26MM

The two projects are independent, that is to say the result of one doesn't affect the other.  In this example the authors go on to suppose your job is dependent on not losing money.  So, you can see with the "safe" project you only have a 40% chance of losing your job, but with the "risky" project you run a 60% chance of being fired.  Since both projects have the same ENPV, most people would correctly choose to invest in the "safe" project.

However, in this example if you were allowed to invest half your money in each project the only way you could lose money is by both projects being unsuccessful (if one is successful it pays for the other being unsuccessful), and since they are independent, the chance of both being unsuccessful is 40% * 60% = 24%.  So, by spreading your money between two projects instead of one "safe" project you have reduced your "risk" of unemployment from 40% down to 24%.  This is the power of the "diversification effect" and is not intuitively obvious to most of us.

The effects of diversification can be even greater when the projects are not completely independent as stated above.  If the projects are statistically dependent then the outcome of one will have an effect on the outcome of the other.  If the outcome of one project increases the chance of a similar outcome in the other, then the projects are Positively Correlated.  If, however, the outcome of one project reduces the chance of a similar outcome in the other, then they are Negatively Correlated. 

In the above example, if the projects were positively correlated, then the 50/50 portfolio would have a greater than 24% change of getting you fired, but if they were negatively correlated you would have an even less than 24% chance of being sacked.  The exact chance would depend on the degree of correlation.  The idea here is risk can be minimized by spreading your investment across many projects and trying to avoid positive correlations while looking for negative correlations. 

As I mentioned at the beginning, this is one reason institutional investors like direct investment in commodities such as oil and gas.  Historically, direct investment in oil and gas has had a relatively strong negative correlation to more traditional investments (stocks and bonds).  So by including some oil and gas investments in a traditional portfolio the "risk" of the entire portfolio can be reduced and moved closer the "efficient frontier" as advocated by Markowitz; of course there are other reasons to invest in oil and gas as Kathy Heshelow outlines on her web site.

These concepts are used by some of the larger oil companies and mostly in determining exploration programs, but my experience is that they are not being used by most of the smaller companies and rarely when looking at A&D programs.  While there are computer programs that can simulate this portfolio effect, most of the smaller companies I am familiar with shy away from this methodology and prefer more intuitive investment strategies; specifically new start-ups who prefer to get their capital invested quickly and would rather take 100% of fewer projects rather than "spread the risk" and delay getting their capital in play.

The general concepts of portfolio optimization can be applied without having to perform the rigorous calculations or build complex computer models simply by practicing diversification and spreading the risk around (several smaller deals instead of fewer big ones) and looking for negatively correlated projects.

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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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When I first started in the oil patch the Spraberry Trend in the Midland Basin of West Texas was known as the "largest uneconomic oil field in the U.S."  Now we all know that uneconomic depends on price, which was $10 - $20 per barrel at the time.

Today, with oil stabilizing in the $80 range, a once uneconomic play is economic. Combine this with an evolving technology borrowed from the Barnett Shale and you have a very interesting play called the Wolfberry.  The name "Wolfberry" is a hybrid of the words Wolfcamp and Spraberry.

Other than the price, the key to the success of the Wolfberry play is hydraulically fracturing (fracing) the Wolfcamp beneath the Spraberry and Dean formations. This Wolfcamp section is composed of interbedded organic shales and limestones. It is the multi-stage fracing of both the Spraberry and Wolfcamp (Wolfberry) that provides the deliverability of hydrocarbons to the well bore.  Today an average Spraberry only completion will produce initially 10 BOPD (barrels of oil per day), whereas you can expect 40 to 110 BOPD when the Wolfcamp in added.  This initial boost in production makes or breaks the economics.

I evaluated 95 productive wells that Pioneer has drilled since 2006 targeting Wolfberry over the entire Trend area.  After evaluating the production curves we see wells that have a:

• 38 BOPD average IP (initial production)
• 114,000 BOE (barrels of oil equivalent) average estimated reserves (EUR)  
• 20% ROR (rate of return) 
• ROI (return on investment) around 2.7

I have seen similar results in the 15 wells I have drilled over the last 2 years. Please note, the above averages are over the entire Spraberry Trend area. Individual county analysis has identified sweet spots in the trend.

Recent acquisition activity, particularly by Concho Resources and increase drilling by Pioneer ensures this play will remain hot. The economics of the play are important to operators to be in the right areas, to landowners for negotiating leases and damages, and to investors because of the opportunity.

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