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

This article was contributed by Staffan Van Dyke as part one of a two part series.

INTRODUCTION

Direct Hydrocarbon Indicators, or DHI's (also commonly known as, HCIs [HydroCarbon Indicators]), are used every day in the oil and gas industry by technical professionals to help search for hard to find, or simply overseen, hydrocarbon deposits. There are many factors that must be taken into consideration to apply seismic attributes properly; to name a few:

1) understanding rock physics;

2) the signal to noise ratio of the seismic survey;

3) poor processing;

4) insufficient (or erroneous) acquisition parameters, and so on.

When gas or oil replace the interstitial brine water in existing reservoirs, the seismic reflection coefficient inherently changes (this is manifested by a difference in the acoustic impedance of the hydrocarbon-bearing zone as compared to the brine-saturated zone either above or below the reservoir in question). This work must be done in order to determine if a well should be drilled OR NOT DRILLED - this cannot be stressed enough; therefore DHI's are a cornerstone application for the hunt of oil and gas deposits. It should be noted that not all seismic anomalies are DHI’s, and not all DHI’s are of equal quality; amplitudes can be caused by factors not related to hydrocarbon accumulations - this is a key point that many geophysicist commonly overlook (this will be discussed in greater detail in Part II of this write-up).

Potential Pitfalls in DHI Interpretations

The relative amplitude value can be deteriorated and/or altered dramatically by post-processing of the seismic data. That is, the numbers associated with the seismic amplitude values are unitless, therefore, they fall into no particular unit scheme (there is a large misconception in the oil industry that all seismic amplitudes fit nicely into a -128 to +128 value scheme - THIS IS NOT SO - in fact, they can range anywhere from -0.00234 to +0.00234 to as high as -14656 to +14656 before processing - simply put, amplitude values are unitless numbers - therefore, they are qualitative, not quantitative.

During processing, erroneous artifacts may manifest themselves in the seismic dataset - these need to be studied with great detail to be certain that they are indeed real or not real; an error of this magnitude could cost a company $100's of millions of dollars, so it is very important to understand what one is doing and if they are going about it the proper way. Therefore, analog data, calibrated well logs, etc., must be used to help determine if these artifacts are true representations of hydrocarbon deposits.

Other major issues include the calibration of wells that are not in the same geologic province because they come from a different environment of deposition, or the wells used to calibrate the data are simply too far away from the well being studied. Additionally, if things such as stratigraphic changes (e.g., going from a channel fill sandstones environment to a thin bedded levee environment) the well ties and the prospects will be wildly different. And perhaps the most common error is the lack of sufficient integration of geological data/interpretations for the prospect being examined.
 

Basic Seismic Attributes Definitions

Bright spots: Local increase in amplitude on a seismic section (presumably caused by a hydrocarbon accumulation)
DHI or HCI: Measurement which indicates the presence or absence of a hydrocarbon accumulation (bright spot, dim spot, flat spot, shadow zone, etc.)
Phase (Polarity Change): Seismic peak changes to a trough (or vice versa)
Dim Spot: Local decrease in reflection amplitude, generally occurs in low porosity sands (10% to 15%)

Figure 01: Flat Spot showing fluid contact of a gas field with an underlying water leg (blue-dashed line)

Figure 02: Gas reflections from the Nile Delta in Egypt; the high amplitude red reflection (trough) is from the top of the gas in this antiformal trap; conversely, the high amplitude blue reflection is from the base of the gas, or from the fluid contact.

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I recently had the opportunity to attend the SPE Annual Technical Conference and Exhibition (ATCE) in Florence, Italy (yes it was very nice). One of the highlights for me was a paper presented by Dr. Lee of Texas A&M University titled A Better Way To Forecast Production From Unconventional Gas Wells. The paper is SPE 134231 authored by Peter P. Valko and W. John Lee, both from Texas A&M University.

In this paper, and another paper authored by John Lee and Rod Sidle, Texas A&M (SPE 130102) a method for forecasting reserves using decline curves is presented. This method, termed “Stretched Exponential Decline” uses a different set of equations than most of us are used to using for forecasting these types of reserves. 

 Historically we have used equations developed by Arps in 1945 which describe three variations of the decline equations for exponential, hyperbolic and harmonic declines; the difference being the value of “b” the “decline exponent.” The general form of the equation is

 q= q_i/(1+bD_it) ^(1/b)

 Exponential decline (straight line on a semi-log graph) occurs when b=0. Hyperbolic decline occurs when b is between 0 and 1 and demonstrates a curved plot on a semi-log graph, like we have seen in shale gas wells during early time production; and harmonic decline occurs in the unique case when b=1.

 In practical experience, hyperbolic declines are often used to forecast tight reservoirs, such as shales, since the shape of the early-time production data can be matched using these equations; however, it is not uncommon for “matched” b factors to be well in excess of 1, which is outside of the parameters described by Arps.  The problem is when the b factor is 1 or greater the Arps equation will approach infinity; which is obviously not possible. In real life most evaluators deal with this problem by placing an arbitrary minimum limit on the production decline and forcing the forecast to an exponential decline late in the well’s life. This arbitrary minimum limit solves the problem of infinite reserves, but it is arbitrary and different evaluators may use different limits.

 Lee et al’s Stretched Exponential Decline takes a different approach. This approach is totally empirical and can be thought of as a sum of a series of individual exponential declines with differing decline rates. In other words, it’s like a given shale well is producing from multiple smaller volumes with each behaving exponentially (heterogeneity). The mathematics are a little more complicated, and definitely outside the scope of this blog, but supposedly Valko has developed software to handle the difficult parts (I have yet to see or use the software).

 The advantages of the Stretched Exponential Decline approach are many; including a bounded EUR (Estimated Ultimate Recovery) and a graphical straight line of recovery potential (rp) versus cumulative production. Experience with the Arps hyperbolic equation is that as more data become available over time for a given well the “matched” b factor is usually reduced from earlier matches suggesting early-time estimates of recoveries may be reduced over time (depending on how the “tail” was handled by the evaluator, as discussed earlier).

 Using decline curves to determine reserves is a very common and important methodology available to the evaluator. This is even more important in the shale-type resource plays where other traditional methods of determining reserves are limited by data availability and our understanding of the production mechanism, and is compounded by the need to determine expected reserves early in the life of a play for business decisions such as leasing and drilling. I don’t know if the Stretched Exponential Decline method will catch on and become the norm, I guess it will depend on the ease of use and whether the economic software providers support it, but I applaud the effort to understand the production mechanism and attempt to create a usable model for the evaluator.

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This article was contributed by Staffan Van Dyke

The objective of this article is to evaluate tight gas sandstones in relation to conventional reservoirs (sandstones/carbonates) as well as unconventional reservoirs (coalbed methane/shale gas), with reference to its constituent petroleum system parameters: source, trap, seal, reservoir properties (porosity and permeability), and time factors (timing of charge and migration). The article indicates significant differences between tight gas sandstones as compared to coalbed methane and/or gas shales. A thorough evaluation of the geological evidence studied for this article indicates that tight gas sandstones, as a reservoir, are closer to conventional type reservoirs than they are to unconventional type reservoirs, such as coalbed methane and/or gas shales.

Utilizing the framework described in this paper, tight gas sandstone reservoirs should then be considered as a sub-type category within the overall conventional reservoir definition, as the majority of its geological properties fall within this definition, and not that of an unconventional reservoir – note: the suggestions laid out in this article STRICTLY refer to the geological parameters of these reservoirs and NOT their engineering parameters (which are still very clearly considered “unconventional”).

Under this definition just laid out, the characterization of tight gas sandstones as an unconventional reservoir is simply inappropriate, as the geological setting / petroleum system / etc., as compared to coalbed methane and shale gas, are very different in their most basic geological constituents, making the comparison (and, hence, the argument that they are indeed very different from one another when viewed in a geological sense). Tight gas sandstones are simply reservoir rocks, whereas coal and shale are considered to be both the source and the reservoir rock.

Unconventional reservoirs are ones that cannot be produced at economic flow rates or they do not produce at economic volumes without the assistance from massive stimulation treatments, such as hydraulic fracturing (fracking) or other special recovery processes and technologies, such as steam injection (these are known as “secondary” and/or “tertiary” recovery techniques). Typically unconventional reservoirs have been described as: tight gas sands, coalbed methane, and gas shales (Holditch, 2003 and 2006). However it is an economic and reservoir engineering definition and does not take into account the geological processes behind the deposition of said deposits.

It is also important to understand that a conventional (sandstone/carbonate) reservoir with low natural pressure that depletes very quickly (in the order of weeks to months) that requires artificial hydrocarbon recovery techniques to maintain or increase its economic viability, is very nearly the exact definition of an unconventional reservoir, as the one given above. However, such reservoirs are still categorized as conventional in the geological sense.

On the other hand, since tight gas sandstones must be artificially stimulated (fracked) in order to produce its gas, it would only seem natural to place this reservoir criterion in the “unconventional reservoir” category.

Comparison of conventional and unconventional reservoirs

In the United States, the tight gas sandstone definition is applied to reservoirs with less than 0.1 mD of permeability (Meckel and Thomasson, 2008). Our investigation indicates that tight gas sandstones have significantly different characteristics in comparison to coal bed methane and shale gas. They are:

1. Tight gas sandstones act purely as a reservoir, whereas coalbeds and shales act not only as their own source rocks, but as well as their own reservoirs;

2. Shanley et al (2004) found that the low permeability reservoirs in the Greater Green River Basin of southwest Wyoming were not part of a continuous type gas accumulation but were low permeability rocks in conventional structural, stratigraphic, and/or combination traps. Earlier, Berry (1959) and Hill et al (1961), proposed that in the San Juan Basin, the gas within the sandstone reservoir was localized in a potentiometric sink associated with down-dip flow of water. In other words, it is a hydrodynamic type trap, thus, much more like the conventional trap settings found in conventional reservoirs;

3. Gas migrates into tight sandstones from the nearby source rock and the charged gas may be housed within the reservoir due to high capillary pressure conditions by virtue of low porosity and permeability, and up-dip presence of water due to regional or local hydrodynamic conditions, whereas in coal and shale gas, it is adsorbed into the matrix of organic matter (Bustin and others, 2009);

4. Many conventional reservoirs are porous and permeable but do not have enough primary energy to support hydrocarbon production unaided at an economic level, but are still categorized as conventional reservoirs. According to the unconventional reservoir definition given above, this quality should then define these reservoirs as unconventional, primarily because enhanced recovery techniques are required for them to be economically producible. Similarly, tight gas sandstone reservoirs need enhanced recovery techniques like fracturing, flooding, and
acidization to make them economically viable. However, instead of categorizing these low primary-energy conventional reservoirs as unconventional, it is the authors’ opinion that they should remain classified as conventional reservoirs, and that tight gas sandstones should be classified as a sub-type within the overall conventional reservoir petroleum system;

5. The only correlatable property of tight sandstones to coal and shale is their low porosity and permeability similarity, unlike the higher porosities and permeabilities typically seen in conventional sandstone / carbonate reservoirs. The geological aspects discussed above suggest that tight gas sandstone as a reservoir is closer to conventional reservoirs (sandstone / carbonates) than to coalbed methane and shale gas reservoirs. Table 1 summarizes the petroleum system and other parameters with respect to tight gas sandstones, coalbed methane, shale gas, and conventional reservoirs to elucidate the similarities between these reservoir types.

Conclusion

Evaluation of the above geological aspects suggests that tight gas sandstones, as a reservoir, are closer to conventional type reservoirs than to unconventional type reservoirs, like coalbed methane and shale gas. It is clear that tight gas sandstones act simply as a reservoir, whereas coal and shale act as a source rock as well as a reservoir for the gas. Tight sandstones may become a hydrocarbon reservoir only when a potential source rock is available within the basin, or a nearby region, capable of charging the reservoir. Utilizing the framework described in this paper, tight gas sandstone reservoirs should be considered as a sub-type conventional reservoir, as the majority of its geological and petroleum system parameters fall within this definition, and not that of an unconventional reservoir.
 

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In “Not All Barrels Are Created Equal” I wrote about the risk-adjusted values placed upon oil reserves depending on their reserve category, and in “What’s In a BOE?” I described how natural gas volumes are converted and reported as “barrels of oil equivalent” (BOE). In this article I want to differentiate between two distinct types of liquid hydrocarbons (crude oil and NGLs) that are both commonly reported as “barrels of oil.”

Crude oil is produced from sub-surface reservoirs in a liquid form usually along with associated natural gas, and water. The raw production stream is run through a separator where the gas and liquid is separated. The oil and water are subsequently separated where the oil can be sold to a refinery, either through a pipeline or hauled on trucks, and the water can be disposed of. The gas is sent down a pipeline to a gas plant where it will undergo a process to remove the heavier hydrocarbons before the “dry” gas is put into a pipeline and sent to market. The heavier hydrocarbons that have been removed from the “wet” gas stream are referred to as Natural Gas Liquids (NGLs).

With a gas well the process is very similar, but without the crude oil. In the case of a gas well any hydrocarbon liquids produced from the well are referred to as “condensate” which is typically much lighter and volatile than crude oil. If the gas produced is not “dry” enough to be taken directly to market, it will be sent to a gas plant for the extraction of NGLs, just as the gas from an oil well.

The difference between NGLs and crude oil is their chemical makeup. Crude oil is a mixture of hydrocarbons from lighter to very heavy, while NGLs are typically composed of only the lighter hydrocarbons (ethane, propane and butane). The reason this is significant is because the market for these two types of petroleum liquids is different since their chemical composition is different. Some companies report NGLs separately from crude oil, but this is not always the case.

This is becoming more of an issue lately because of the tremendous surge in development activity of resource plays particularly targeting the “oilier shales.” As oil and gas prices continue to diverge companies are actively moving from pure gas shales to the oilier shales to reap the profits of the recovering oil market. This move can be seen in the graph of recent rig activity presented by Slyvia Barnes (MadisonWilliams) at the Hart A&D Conference last week.

This industry shift, and corresponding increase in supply, is putting pressure on the NGL market. Another graph from Ms. Barnes presentation demonstrates the relationship between crude oil and NGL prices. There is concern in the marketplace that as the attraction of these “oily” shales continues to increase the supply of NGLs, the disconnect between the value of oil and NGLs will expand.

As this industry trend continues to play out it is becoming even more important to understand the difference between an oil play and an “oily gas” play. Some resource plays are oil (Bakken, Wolfberry, etc) while others are either gas or “oily gas.” Here again, we see the need to fully understand the assets we are dealing with and the risk associated with valuing assets solely based on reported BOEs.
 

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When it comes to developing the Spraberry field in West Texas, Pioneer continues to rewrite the book. In the past we have discussed the Spraberry field and how the addition of the Wolfcamp lead to the “Wolfberry” play. Now it appears the Strawn formation is being added below the Wolfcamp and the results are encouraging…thus the “Strawberry” is born.

Pioneer plans to drill 440 wells in their Spraberry/Wolfberry/Strawberry play in 2010. This is up significantly from their earlier estimate of 125 well. Of the wells remaining to be drilled in 2010, approximately 40% will be drilled down to the Strawn. Pioneer reports wells that have included the Strawn with the Spraberry and Wolfcamp have seen an increase of 20-30% in their IP rates above the average of 60 barrels of oil equivalent per day (BOEPD).

This increase in IP is significant because it allows for the faster recoupment of the investment, which increases the rate of return of the project. I have not seen any numbers reflecting the increased reserves associated with adding the Strawn, so I cannot comment on the affect the Strawn will have on the overall finding costs. Let’s hope the Strawn’s reserves can support the additional costs associated with drilling deeper and adding stages to the frac job.

The Spraberry, and Wolfberry, and no doubt Strawberry plays have always been very sensitive to developments costs. Pioneer has addressed this aspect by not only the sheer volume of development activity, but by also providing their own services. They currently plan on providing 30-60% of their own services internally by 2012. Pioneer is increasing the company-owned frac fleet from one to four, and the number of company-owned drilling rigs from six to twelve.

The results speak for themselves. Pioneer reports an average gross investment of only $1 million for the wells drilled in the first half of 2010 and an associated rate of return of 50% (BFIT). How much of these results include the Strawn is unknown, but if they can consistently increase their IP by 20-30% and continue to hold development costs down, the Strawberry Fields may continue for some time—but forever?
 

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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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The August 2010 issue of JPT (official publication of the Society of Petroleum Engineers) features a guest editorial by Michael Collier, Partner, Houston Transaction Services Group, PricewaterhouseCoopers in which he makes several interesting observations about the current state of M&A activity and speculates about future activity.

“One sure sign that the economy is in recovery mode is the increase in merger and acquisition (M&A) activity, including the USD 60 billion of deals in the energy sector in the first quarter of 2010. The depth and breadth of the M&A rebound in energy has been fueled by optimism that we are emerging from a global financial “funk” and we are at the beginning of a long period of sustained economic growth.”

Mr. Collier goes on to credit the resurgence in M&A activity to “pent-up demand” and the new “shale-gas paradigm.” He also credits the recovering stock market for leveling the playing field and “allowing senior executives to see stock-for-stock deals as fair.” “Until recently, it was difficult for both buyer and seller to see any particular acquisition price as the right price because earnings of target companies were declining. As the overall economy improves and sellers report steadily improving quarterly earnings, price expectations between buyer and seller are coming into line.”

As for the future, Mr. Collier predicts “When [price expectations between buyer and seller] are finally aligned, which often happens four to five quarters after the economy begins to recover, then we will see not only corporate cash-for-stock deals become common, but we will also see private equity firms come off the sidelines with a major wave of transactions.” However, he also sees some changes in the way deals will be evaluated, “Given the changing economic variables, and some lingering uncertainty in the capital markets, deal-making experience and savvy will be a valuable ‘commodity’. Our corporate clients are starting to recognize these challenges and are making changes to the way they pursue deals. In fact, we have seen them work hard at getting smarter and in some instances, they are adopting some of the skill sets of petroleum engineering firms to better compete and succeed.”

Mr. Collier sees shale-gas as a potential game changer. “Not only does it create the possibility of a dramatic change in the hydrocarbon supply/demand equation, but it has driven and will continue to drive M&A.” Shale-gas has indeed impacted the US energy industry for a number of reasons and Mr. Collier comments on one of the more interesting aspects, “…the rush to exploit shale gas has also triggered a rush to acquire oil reserves. Although this new ‘oil rush’ surprised many industry observers, it now appears quite logical. With gas prices likely to remain flat (given the tremendous gas supplies found in the shales), there is a new expectation that independent oil companies in particular will be rewarded for oil reserves in the portfolios in the intermediate term.”
 

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Let me begin by first explaining that I am not an attorney, nor am I a landman. I have been involved with several unitizations and poolings, and I have relied heavily on the advice of attorneys and landmen during these procedures. The purpose of this entry is to give an overview of unitizations and poolings, their purpose, pros and cons, and things to consider should you find yourself faced with either.

Basically, the purpose of both unitizations and poolings is to combine individual leases into a single entity for the purpose of development. Pooling is usually associated with drilling a well when the individual lease size is smaller than the required statutory well spacing. For example, if there are several contiguous 10 acre leases and an operator wants to drill a well which requires 40 acres, then the operator will pool four of the smaller leases together to form a 40 acre pool on which to drill. The purpose is to prevent waste since drilling a well on a lease smaller than the expected drainage area would require each adjacent lease owner to drill a competing well to prevent drainage—in this example four wells would need to be drilled instead of one.

In pooling, as described above, the resulting “pool” is not intended to represent the entire reservoir (sometimes a reservoir is unfortunately called a pool). This is where unitization differs from pooling. Typically the purpose of unitization is to combine all the leases in a given reservoir or field for the purpose of enhancing the field’s recovery. This is usually necessary in the cases where a flood (waterflood, steamflood, CO2 flood, etc) will be pushing oil and gas around and may cause hydrocarbons to cross lease lines. It is much more efficient to design and operate a flood without having to worry about keeping lease A’s fluids from crossing over to lease B.

In both cases the most important thing is for everyone to get their fair share of the resulting production. In the case of pooling this is commonly done based on acres contributed—if your 10 acres are pooled into a 40 acre pool, then you get 25% of the pool. This is usually the case because the leases are small and the producing formation probably doesn’t vary much between the leases, and if there hasn’t been any drilling yet there usually isn’t much data available to argue about. This is not always the case however, and you can imagine if your lease is sitting on top of a structure and you are being pooled with down-dip leases you may feel you are entitled to a bigger portion.

Unitizations are usually much more complicated. This is because they are typically much larger, involve several wells, often with different operators, and since they are usually in preparation to flood a reservoir there is much more data available to argue about. Also, when converting a field from primary lease-based production to a unitized enhanced recovery flood often some producing wells will be converted to injection and the associated loss in production will take time to recoup. This means the cash flow being generated will be reduced at the same time capital investments are required to install the flood; which usually increases the anxiety in the room.

Several different parameters are typically used to determine each lease’s equitable share in a unitization. Since the primary purpose is to recover remaining hydrocarbons, the original hydrocarbon pore volume and remaining recoverable hydrocarbons per tract are usually very important parameters, as are the current production rates, usable wells, and sometimes acres and cumulative production are used. The goal is to get all the parties (operators and mineral owners) to agree on one formula that divides up the future production and share of the costs (for the working interests). Usually a lot of negotiating is required and sometimes very creative unitization formulas are the result.

Both pooling and unitizations have their purpose in developing an oil and gas reservoir and both have been used for years as a means to prevent waste and increase recovery. As with most everything there have been abuses and inequities in the past and there will no doubt be more in the future. The most important thing to remember is to be sure to understand what is going on, what your lease allows and what options you have available to you, because these things will be very important to you when you’re sitting in a conference room negotiating for your piece of the pie.
 

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It seems like hardly a week goes by anymore without two large oil and gas companies announcing a new JV. Most of the recent JV announcements involve the development of new, hot shale plays. Chesapeake Energy is certainly one of the leaders in this development concept and has announced several different JVs covering most of the current unconventional shale plays, with some very large partners.

Why the interest in a JV? There are several reasons a JV is attractive to the parties involved on both sides of the deal. From the originator’s (or seller’s) side the JV raises capital, allows for the diversification of development (spreads the risk), and leverages-up the returns on the development investment by virtue of the “promote.” From the partner’s (buyer’s) side the JV is a means to enter a hot new play that has been delineated without having to participate in the “land rush” that always precedes these plays, and provides instant access to experienced personnel thus reducing time on the “learning curve.”

With the various unconventional shale plays that have heated up, from the Eagle Ford to the Bakken to the Marcellus and everything in between, there is a common timeline that begins with companies and promoters secretly buying up leases; this requires a lot of time, effort and money. This lease bonus money is at risk because the play is in its infant stage and the acreage you are leasing up may turn out to be non-productive, or the play itself could fizzle out. Companies like Chesapeake and EOG (and others) have taken these upfront risks along with the time and costs associated with developing the drilling and completion expertise specific to each play, but then face the capital requirements necessary to develop their leases. The capital necessary to develop these plays is staggering with costs ranging from $3-10 million per well (more in some cases). Even with companies this size, drilling 100 $10million wells can put a strain on your cashflow.

The company “selling” the JV usually gets a cash payment upfront that allows them to recoup these out of pocket costs and provides capital to continue their development program. The other aspect of the JV is the “promote” which allows the “seller” to develop the asset at much more favorable terms and with less capital. Some of the recently announced JVs have “promotes” on the order of 60% for 25% (Chesapeake/Total Barnett), or 75% for 45% (Pioneer/Reliance Eagle Ford). This means the “buyer” pays for 60% of the drilling costs in exchange for 25% of the well once completed. This is a huge advantage for the “seller” going forward as it leverages up the return on investment and lowers future capital requirements.

On the other side of the equation is the “buyer” who pays the upfront cash and absorbs the “promote.” Usually the buyer gets some PDP production which helps justify the initial cash payment, and steps into a development program which has been delineated (manageable risk) with a partner who has a proven track record. The return on the future development capital will not be as robust for the “buyer” as a result of the “promote,” but they have not been exposed to the initial risks or costs associated with the exploration aspect of the new play. This reduction in upfront costs and risk, combined with the prospect of rapidly climbing the learning curve and perhaps using the technology elsewhere, justifies absorbing the “promote.”

Based on the recent JV activity level there seems to be a continued appetite for this type deal and I anticipate more announcements in the future.

Update:  Another Eagle Ford JV anounced between Abraxas and Blue Stone.
 

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