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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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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The Chinese government recently sentenced an American citizen to eight years for selling data relating to the locations and reserves associated with more than 30,000 Chinese oil and gas wells to IHS. The sentence has provoked demands from US officials for Xue Feng’s immediate release and deportation to the US.

As outrageous as this may sound to Americans accustomed to “freedom of information,” we should look in the mirror before we judge the Chinese too harshly.  Here in the US we can usually purchase this type of information (well locations, production data, well logs, etc.) from companies such as IHS, Tobin, and others, or in many cases get the data for free from state regulatory agencies; but this is not always the case.

I was recently involved in an Eminent Domain case which involved a large interstate pipeline company wishing to expand a gas storage facility. In this case the pipeline company was concerned that its storage gas may leak out of the boundaries of the existing facility onto the property of nearby landowners. The pipeline company was exercising its federally backed right to take the mineral rights of these owners so it could expand the storage facility to prevent this potential loss.

Despite the fact the pipeline company was taking the property of these citizens, they refused to disclose the locations of their wells, the current and future boundary of the storage facility, and their geologic justification for the expansion. They claimed “national security” as their basis for withholding this information from the citizens being impacted.

While the US government hasn’t nationalized its oil industry, these large interstate pipelines and utilities have been granted powers approaching that of a NOC. US oil and gas companies are required by most states to provide this type of information with the knowledge that it will be made publicly available, but these interstate pipeline gas storage facilities can hide behind the federal government (FERC).

So, before we start making demands of other countries let’s take a minute to think what the repercussions would be for an employee of this US pipeline company had they sold their “national security” secrets to IHS.

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"We think there are a lot of opportunities out there. The shale plays take a lot of capital to drill all those leases…companies generally have to issue equity, structure additional debt, or sell their non-core conventional assets—which are what we want to buy."  -Alan Smith, Quantum Resources

In a recent article on OilandGasInvestor.com Leslie Haines interviews Alan Smith of Quantum Resources Management about the recent $900 million acquisition of Denbury assets.  It sounds like Quantum has a good investment plan targeting conventional assets (instead of the ultra-hot shale plays) in well established producing basins, and focusing their capital on enhancing existing production through infill drilling and waterfloods.  

Its refreshing to hear a company talking about doing business the "old school way"-- buy quality assets in mature basins and focus your efforts (and capital) on developing your assets with low risk drilling and flooding; not to mention the portfolio diversification effect of mixing oil and gas assets in different basins.   In the interview Mr. Smith refers to his business philosophy as "contrarian," but I would call it "good business."

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In a recent article Nissa Darbonne discusses some interesting issues surrounding the Oil and Gas industry in light of the well control events is the Gulf and Marcellus Shale.  These events, along with the publicity surrounding the large fracture stimulations being used in today's shale wells, will most likely lead to new regulations for drilling and completing wells in the US. 

What impact these new regulations will have on the industry and the profitability of some large development projects is yet to be seen.  We know offshore insurance rates will increase significantly for those who can find insurance, and many companies will be forced to self-insure or exit the Gulf.  This begs the question, how do you exit the Gulf in today's environment?  This is certainly not a seller's market for offshore assets.  So, if your company has offshore assets in the Gulf and you can't find affordable insurance, yet you can't afford to self-insure (assuming the government will allow self-insurance) and you can't find anyone willing to buy your assets for a reasonable price, what can you do?  This problem is only compounded by any offshore drilling moratoriums which could put into doubt future development programs, or at least their near-term timing. 

Regardless of these recent events and the public policy changes that may result, the country's energy needs are growing and will have to be met with an increased domestic supply of hydrocarbons.  So, despite the inevitable fact that the rules of the game will likely be changed, domestic oil and gas is not going away.  As Nissa Darbonne's article points out, this is another reason to diversify your portfolio. 

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I used to give a talk on reserve determination methodology to the "non-technical" staff at a previous employer.  Below is a summary of that talk.

First, let's make sure we are all on the same page.  Oil and gas is made up of hydrocarbon molecules of differing size.  The size of the molecule is determined by the length of the carbon chain.  The greater the length of the carbon chain the greater the size, weight and energy contained within the molecule.  Methane (CH4), for example, is the smallest of the hydrocarbons with only one carbon atom.  Methane is the lightest of the hydrocarbons and the main component of natural gas.  Octane is another molecule that most of us have heard of and it has a carbon chain consisting of 8 carbon atoms.  Octane is heavier than methane, contains more energy and is typically a liquid.

Petroleum in its natural state, that is when it's in its underground reservoir, usually consists of a complex mixture of hydrocarbon molecules.  The composition of this mixture combined with the reservoir's temperature and pressure determine whether the petroleum will be in a liquid or gas phase in the reservoir (it is possible to have a solid in some special circumstances). 

A petroleum reservoir is not a pool of oil floating in an underground cave.  The reservoir consists of "solid" rock; well nearly solid.  A reservoir rock has porosity (small holes within the rock that are usually not visible with the naked eye) and the hydrocarbons are contained within these pores in the rock.  There are three substances found in reservoirs (not including the rock itself): Oil (liquid hydrocarbons), gas (gaseous hydrocarbons), and water.  Hydrocarbons are lighter than water, so they tend to "float" and rise to the top of the reservoir.  Gas is lighter than oil, so it wants to be on the top of the hydrocarbon mixture. 

For a petroleum reservoir to exist it must have a means of trapping the hydrocarbons from floating away and forcing them to stay within the confines of the reservoir.  Since hydrocarbons were generated millions of years ago, these traps that make up today's reservoirs have to be pretty good barriers to fluid migration.

Okay, so now that we are on the same page we can discuss how we can determine the size of a hydrocarbon accumulation contained within a reservoir.  There are basically three different methodologies commonly used to determine the volume of oil and gas in reservoirs.  These methodologies are used both independently and in combination.  The selection of the appropriate method is determined by the characteristics of the specific reservoir, the judgment and experience of the evaluator, and the data available.

The first and most common methodology is the use of decline curves.  Decline curves are used when a reservoir has been on production for some time and has demonstrated an observable trend (decline) in production rates.  The technique is to construct a graph of production rate versus time on a semi-log scale (where production rate is on the log scale and time is on the normal scale) and then forecast the observed trend (decline) forward in time. 

The art is in the forecasting of the decline.  Some reservoirs exhibit a straight line (exponential decline) while others follow a curve with a lessening slope over time (hyperbolic or harmonic decline).  Obviously the selection of the appropriate decline shape makes a big difference in the production forecast and thus the reservoir's reserves.  The basic assumption in using a decline curve to forecast reserves is that the historical conditions that existed when the decline was observed will continue throughout the forecast. 

Decline curves are the most commonly used method for determining PDP reserves because they can be constructed and forecast quickly, but this also occasionally results in their inappropriate use.  Care must be taken to determine when it is appropriate to use a decline curve and when an additional or alternative method is required.

The second most common method of calculating reserves is to volumetrically determine the size of the reservoir.  This method is called "volumetrics" and requires some knowledge of the shape and size of the reservoir including its areal extent, thickness, porosity (percent of rock that is pore space) and relative saturations of oil, gas and water.  This may sound easier than it actually is.  Usually an experienced geoscientist is required to construct structure and "net pay" (the portion of the rock that contains hydrocarbons) maps of the reservoir and this in itself is subject to interpretation. 

Given this geological information, and using basic geometry, the volume of the reservoir and its hydrocarbons can be calculated.  This methodology results in the volume of hydrocarbons in place (OIP and GIP), but a separate determination must be made about how much of the hydrocarbons can be recovered (recovery efficiency). 

Often volumetrics are used to determine the reserves associated with development or exploration projects (PDNP, PUD, Probable and Possible).  This is because there usually hasn't been any production from the reservoir (the well hasn't been drilled yet) so the other methodologies, which rely on historical production data, can not be used.  This gives rise to the common perception that volumetrics are less accurate than the other methodologies.  This perception is not necessarily true, it's the project itself that has a greater degree of uncertainty.

The third methodology is more complicated and less intuitive to many.  This method is referred to as "material balance" and is based on the concept of mass balance.  Simply put, the mass of anything in a container is equal to the mass originally in the container, less what's been taken out, plus what's been added in.  Another way to think about it is if you have a large container of gas with a fixed, but unknown, size (like a propane tank for example) and you measure the pressure drop of the container as you pull out a known volume, with some knowledge of the expansion properties of the gas, you can back calculate the volume of the container.  

Material balance methods are complicated and require a lot of data (historical production, reservoir pressures, physical properties of the fluids, drive mechanism, etc), but when sufficient data is available they can give very good results; however, if the data is not available or is of poor quality then the results can be misleading. Computer based simulation models are typically based on the material balance methodology.  This methodology is nearly always utilized in conjunction with one or more of the other two methods and by comparing the results the evaluator can learn a great deal about the reservoir. 

All of these reserve calculation methodologies have their strengths and weaknesses and it is the responsibility of the evaluator to determine the most appropriate method.  Each method requires some degree of judgment on the part of the interpreter and it is important to know and understand the assumptions used and the potential errors that may result.

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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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