Oil Crisis: Investment Dream or Acquisition Nightmare?

Buying low and selling high in this market only works if you know the TRUE value of your acquisition.

Nobody, and I include myself, can predict oil prices for the immediate future. However, I do have another type of prediction…more new domestic oil and gas companies will be formed in the next five years than in any similar time frame in the history of the United States. This is for one simple reason, at these prices, oil is the safest investment simply because it is well below its replacement cost. If you look at the true full cycle cost of development and production, today’s price means that it is not possible for the U.S. to sustain exploration even at its present low level. No new exploration means no new reserves and less future production, which eventually leads to lower production and higher prices. So buy low and sell high.

I am not the only one who believes this, which may be why we see record amounts of capital gathering on the sidelines, waiting for the right investment opportunity. So the question is, what should you buy?

In working with our clients to help evaluate acquisitions, here is what we’ve discovered: A typical acquisition in the shale consist of a scattering of wells and leases across a broad area. Pooling agreements usually determine the working interest (expense) and net revenue interest (income) on each well based on tract acreage contribution to the “production unit”. This means that one acre in this unit has a separate and distinct value that is different than one acre in another unit, in the same area, and even on the same lease. The value of each acre is dependent on where it is located, what depths/horizons are part of that acre, how much is developed, and how much undeveloped is remaining. When buying acreage, you need to know how many more wells can be drilled within that unit as per the pooling agreement, as it is now common to see multiple wells drilled within any unit.

Recently we came a across a situation in which the oil and gas lease contained two adjacent tracts of land on the same lease, each tract was in its own separate producing unit for the Haynesville shale formation. One of the units had six producing wells (fully developed) and the other tract had one producing well (five potential additional locations), all drilled during higher gas price years and within two years of each other. Production and depletion for all of the wells was similar, so the depletion type curve, EUR’s for each well, cash flows, and remaining present values would all be the same. One might assume that based on today’s commodity price and the fact that no new wells can be economically drilled, that the value of each tract is based solely on the value of its current production. This assumption would be a mistake, and here’s why…

The unit with six wells is “fully developed”, meaning the reservoir has been fully developed and no more wells will be drilled in that unit, regardless of future commodity price. However, the tract in the unit with only one well drilled and producing can offer five new locations, when prices recover. So the value of the “underdeveloped” acreage has a greater income potential than the fully developed acreage. Think of the undeveloped acreage as an open ended call option. Meaning that at some time in the future, as long as the lease/tract is HBP, the owner of that lease has the right, but not the obligation, to drill additional wells. So, if and when commodity prices rise, the “undeveloped” tract becomes more and more valuable.

Also, it’s important to be aware of which leases have depth/horizon severance issues as well as horizontal and/or vertical pugh clause issues. With this awareness, you can determine what you can keep and what you will lose, as well as how much to budget for future payments and when to pay them.

The key to doing intelligent and effective due diligence and evaluation of an acquisition is to look at and value each tract of land, considering its present EUR and future EUR potential. As prices rise, the tracts with the least amount of developed producing wells will have a greater increase in value than those tracts that are more fully developed.

Tim Supple 2, President of iLandMan

With today’s database and GIS technology, this process can be simple, fast, and well worth the investment. Otherwise, I honestly do not know how anyone can truly be knowledgeable and competitive in acquisitions in today’s environment.

Tim Supple – President – iLandMan

New E&P companies deserve, and should demand, a new status quo.

One of our competitors (that I hold in very high regard), wrote a great article on the need for oil and gas lease brokers to change the “status quo” of how they work. The gist of the article pointed out that for lease brokers to stay in business, they would have to adopt new technology to bring value and cost savings to their clientele. The “status quo,” he said, just won’t do. I couldn’t agree more, but then again I am biased, because that technology is what we sell.

Expanding on that theme, I suggest that it’s time for the oil and gas companies themselves to lead the way with adoption of new technology. It seems only obvious to me that if they want to cut their E&P cost, the first place to start is with lease acquisition. After all, these are the core assets of any E&P and the very basis of all company value. What they own is what they are worth.

Stack of Stuffed Manila FoldersWe all know the present status quo: The E&P company landman hires a lease broker to buy leases and the lease broker hires subcontractors (field landmen) to do the leg work. The field landman creates reports and paper files for the lease broker. The lease broker’s staff recreates the same reports, along with more copies, and then sends them to the E&P client. At the same time, that E&P client is receiving different reports in different formats from multiple brokers. The lease analysis staff recreates the “lease folder” with the new reports, along with more copies. Then it goes to the accounting department, who makes more copies, creates more files, and does more data entry. Finally, when this absurd dance is done, it all goes into filing cabinets, or if they are really cutting edge, some PDF “filing cabinets”.

After all this mailing and emailing of files, copying of paper, and creation of new reports from the same data, what has been accomplished? The E&P still doesn’t know what they own. Many E&P’s think that their best bet is to put all of that into an accounting database… built 30 years ago… before the internet and online software.

The data is not put into a database by the field broker who is the source of the information. This is what is needed to really tell them what they own. Instead, the process looks more like our industry’s version of the children’s game “Telephone:” What the field landman told the broker, who told the lease analyst, who told the database operator, who told the accounting department, who put that info into a database that might be older than he/she. What can go wrong with that, besides the fact that it’s always several months behind and will never give them an accurate acreage number?

With the sales of large acreage positions from company to company, a large part of our business is now taking lease files and data from the older database models, and converting it all to modern data formats. What we have found is that the acreage counts are always, and I mean always, wrong on an average of at least 20%. Within modern tract-based lease management software, the brokers doing the field work are instructed to use the same database platform to perform all tasks including title, negotiations, lease preparation, mapping, title curative, and more. The new lease files are going digital, paperless, accurate and linked to real time GIS mapping, and cost are dropping quickly and substantially.Tim Supple, President - iLandMan

If you are still having your staff or brokers build new “lease files” from old “lease files”, you really should look at what is possible with new technology.

New companies, new technology, new “status quo”.

Tim Supple – President – iLandMan

Oil Crisis: Is anyone guarding his assets? Anyone? Anyone?

I’ve been wondering about something lately and have been asking around. The reaction I get reminds me of the movie “Ferris Bueller’s Day Off”. Remember the teacher asking the class history questions, getting no response, and saying “Anyone, Anyone”?

Ferris Bueller - Ben Stein - History TeacherHave you heard of the term “contango”? This is a situation where the futures price (or forward price) of a commodity is higher than the expected spot price. Sound familiar? This is what is happening with oil today; “I’m not selling my oil today, because it will be worth more tomorrow.” In the past, producers would produce the oil or a buyer would buy oil today and store it, and then wait for prices to go up before selling or simply forward sell at the higher price. The trick is that the cost of storage has got to be lower than the spread between the spot price and futures price. This is an old technique in our business, but now has a new twist.

E&P companies, primarily in the shale, are doing something unusual. They are drilling wells, but not completing all of them. As a general rule in 2013 The Hess Corporation said the average cost to drill a well in the Bakken was $4.8 mm to drill and $3.0 mm to complete. The backlog of wells drilled, but not completed, has been given the name “fracklog”, and it’s a growing trend. According to Harold Hamm, CEO of Continental Resources, “About 85 percent of U.S. wells aren’t being completed right now…” Bloomberg reports that there are over 3,000 of these wells.

Let’s say you drill, but don’t complete the well, to save the “completion cost,” hedge your bets, and wait for higher prices. You are effectively storing the oil in a natural reservoir (“contango”) and building a fracklog inventory. The big question is, how are your leases going to be maintained? Every lease I have ever seen, and that’s a whole lot of leases, has a shut in provision which allows the operator to pay to extend the lease beyond the primary term if the well is shut in, but only for a fixed period of time and usually only if it is “capable of producing”. What I don’t know is whether or not this growing list of fracklog wells can be classified as “shut-in”?

What happens if the same lease has vertical or horizontal pugh clauses? It is estimated that over 65% of leases taken in the shale plays contain horizontal and/or vertical pugh clauses, with an even higher rate of horizontal and/or vertical segregations on resulting assignments. I’m calling this the “commoditization or valuation on a formation basis.” The question I have is will the shut-in payment on non-completed wells hold all of the lease or only the unitized/pooled acreage by depth or even any of the lease? If it does, what about the non-pooled acreage and all “deeper” depths?

This is not just an academic question. It is truly a big financial question. If these non-completed wells cannot hold lease acreage or deeper depths, how will that affect the “reserve” values of the companies? I was looking at the difference between Proved Developed Producing Reserves (PDP) and non-producing reserves (which goes by many names, like Proved Undeveloped Reserves, Potential Reserves, and Resource Potential) listed on the investor presentations of several big shale E&P companies. What I found interesting is the huge spread between the two categories! Non-producing reserves were usually around 6-10 times greater than Proved Develop Producing reserves.

So the question still remains, if you don’t complete the well, how are you going to hold all those leases, which obviously hold all those reserves, which make up a major portion of the company asset value? After speaking with a number of oil & gas attorneys and principles of E+P companies, I haven’t found anyone who feels confident about an answer in either direction.Tim Supple, President - iLandMan

I think it is going to be a huge factor in how a company maintains its “undeveloped” acreage position and thus its balance sheet asset valuations. We have spent a year developing our program to tell you exactly which leases, which depths, and what acreage your company will lose and how much it will cost to keep that acreage for the next year.

So what do you think about the scenario at hand? Anyone? Anyone?

Tim Supple – President – iLandMan

Oil Crisis: Horseshoes and Hand Grenades

With the downturn in commodity prices comes a reduction in drilling activity and capital expenditures. E&P Companies will be looking at their balance sheets to maximize value on what they already have in inventory. That will include PDP (Proved Developed Producing) as well as PUD (Proved Undeveloped). Horseshoes

Prior to shale, a typical E&P would have 80% of their asset value in PDP and 20% in PUD. As late as 2010 this reversed to 20% in PDP and 80% in PUD. These PUD’s were valued on a per net mineral acre value. Therefore the vast majority of the value of the company was in their undrilled acreage. While this has been changing with drilling activity, even today it is common to see a company value its PUD at 50% of its total assets. With reduced drilling budgets these valuations will be with us for several more years.

Recently this was apparent when facilitating the acreage reconciliation of a sale where there was little producing acreage and the price was $6,000 per net mineral acre (the total sale was in excess of $150 million). With the commoditization of acreage within the shale plays being valued at dollar per net mineral acre on a formation by formation basis, valuation of the company not only becomes more complex, but more important than ever. This is especially relevant where the PDP and PUD overlap at different depths on the same acreage.

Hand Grenades Somewhere along the way, the question was asked, “Are we the owner of the net mineral acres at all depths?” More and more the answer will be, “No, not at all formations.” In every shale play there are multiple formations with potential value. Just as companies sell or farmout their leased acreage based on formation severance, so too have the mineral owners began to insert both vertical as well as horizontal depth limitations and expirations by area and depth. These clauses, commonly known as “pugh clauses,” will greatly affect the company’s value over time. The next round of leasing will see even more of this.

If you look at any E&P company’s valuations you will see more focus on value of net mineral acres on a formation by formation basis. How many net mineral acres they own in the geographic area, like the field, county, shale play and more, is almost irrelevant. What is crucial now is how many net mineral acres they own, at each depth, within a specific geographic area. With “sweet spots” being identified in each active shale play, the net acres in these spots are valued higher than the surrounding acreage.Tim Supple, President - iLandMan

This, of course, means more and more responsibility will be placed on land departments for accurate acreage counts by formation. These E&P’s will become more reliant on either brokers or their own lease analysts to give them accurate net acre counts. With acreage trading anywhere from $6,000 to $15,000 per acre, per formation, unlike horseshoes and hand grenades, “close enough” will no longer be an adequate response.

Tim Supple – President – iLandMan

Oil Crisis: Danger or Opportunity?

The Chinese symbol for crisis is composed of two sino-characters that can represent “danger” and “opportunity”. So which applies to the present state of the oil business? The answer is both.

Chinese Symbol for Crisis - Danger and OpportunityThe good thing about getting older is that nothing surprises you anymore. While the drop in oil prices may have taken everyone by surprise, it is of no surprise… that we were surprised. We have been here before. And while almost everyone has an opinion on when or if it will it recover, I do not. I can honestly say I have no idea what is going to happen.

Here is what I do know; this may be the best opportunity to enter the oil and gas business that I’ve seen in my career (my very, very long career). Sounds nuts right? Well let me explain.

BUY LOW. SELL HIGH. Any acquisition of oil and gas assets at this time will be based on the “current” price, not some price we wish it to be. If you look at crude futures you see March 2023 deliver at $68.26/barrel (+/-). Lenders will use the lesser of futures prices or even lower to fund exploration and production, but effective yield rates will be the same. Whatever the future brings, investing now at $50/barrel is much less riskier than investing at $100/barrel.

DEBT WILL CREATE A “BUYER’S” MARKET. From WSJ Aug 4, 2014: “The E&P sector in 2007 was carrying $28.84 of net debt per barrel of oil equivalent produced, according to data from IHS, roughly equal to operating cash flow. By last year, net debt per barrel had jumped 36% to more than $39, while cash flow was essentially flat.

Even before the drop in oil prices, E&P debt was at an all-time high and has not decreased, but the drop in price has decreased the companies’ ability to pay debt. They will be forced to sell. Many of their leases have multiple pay horizons not yet exploited, and at current prices, little value. This creates the opportunity for future value, when and if prices come back.

HERE’S THE GOOD NEWS. There will be a lot of new capital coming into the oil and gas business to take advantage of this “buying” opportunity. New companies that no one has heard of, with capital from new sources, will enter the market with low debt/barrel ratios and therefore they will be more stable than their predecessors.

These companies will be shedding old methods and looking for new technology to create efficiencies and lower administration costs. Some will even begin using the “virtual” model, meaning there will be no “corporate” office in the traditional sense. They can now lean on a network of skilled and professional oil and gas personnel operating in the cloud. Technology will open up opportunities to hire the best and brightest, wherever they live. The company President can be located in New York, Geophysics, Geology and Engineering in Houston, Operations in Tulsa, Land in Dallas, and Land Service Companies all over the map.

Tim Supple, President - iLandManIs there danger? Yes, but opportunities for new E&P’s are boundless. Our focus is on supporting those companies willing to take on the challenge and embrace these exciting opportunities.

Tim Supple – President – iLandMan


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