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Oil & Gas Investing

Copyright James D. Henry 2012

Be forewarned that there are pitfalls as well as advantages to direct investing in oil and gas deals. Dry holes are an inevitable part of the game, and unscrupulous promoters are out there waiting to prey on the greedy and gullible. After oil and gas prices crashed in 2008 and again in 2015, a lot of drilling deals went sour, and the petroleum exploration business got a bad reputation with the investment community that it did not necessarily deserve. Much of the money that was lost then was invested unwisely for one reason or another, and a lot of the red ink could have been avoided by investors doing a little advance research into this risky and fascinating business. Let’s take a brief look at how the oil and gas game is played and see if it might be a suitable investment vehicle for you.

 KNOW YOUR PARTNERS

Legitimate exploration companies, however small they may be, all have some kind of a track record. If the drilling deals they are selling are registered with the Securities and Exchange Commission, that record will be spelled out in their prospectus. If their deal is not registered (as is the case in the majority of instances), then you will have to ask around about them. Fortunately, in any given petroleum province in America, the oil business is a fairly small and close-knit community, and you generally won’t have to snoop around very long to find someone who knows something about the company or individuals with whom you are considering investing.

The questions that you will want to ask would be fairly standard ones in any industry: How long has this company been in business? Do other oil companies like or hesitate to do business with them? Have they ever (especially recently) been in serious financial trouble (or bankruptcy court)? Is the operator’s nine-year-old son on the payroll at a fat salary? How about the operator’s cousin? Nephew? Brother-in-law? Spouse? Parent? Do they make most of their money off of up-front promotional fees and/or monthly operation charges, or do they make it from oil and gas production? Are their investors from five years ago still spending money with them? What sort of reputation do these people have for: 1) honesty, 2) finding oil, 3) paying their bills, 4) maintaining their producing properties in good condition, and 5) taking good care of their business partners.

Well, you get the idea. You’ll never get the answers to all of these questions, but you should get a feel for how this oil company is regarded by its peers and previous investors. As a general rule of thumb, if you would have any hesitation about buying a used car from those people, you should not be investing with them in a drilling deal.

The individual or company that causes a well to be drilled in search of oil and gas and who maintains the property after production has been established is called the operator. In the US all operators are registered and bonded by the state(s) in which they drill. It is usually—but not necessarily always—the operator from whom you will purchase your interest in the proffered deal. Sometimes deals are brokered by intermediate third parties working in close concert with the actual operator, and that’s fine; just try to remember that middlemen are going to get their share of the pie too. Here’s what you should know about how things work behind the scenes at the operator’s office:

 BEHIND THE SCENES

The first step in any oil and gas deal is the generation of a prospect; this is almost always the job of a geologist. That geologist may be a full-time employee of the operator, in which case he/she may be paid a straight salary and have no direct financial interest in his own prospects. But on the other hand, he may be an independent geologist who sells the intellectual fruits of his labors for a prospect fee and then gets an overriding royalty interest (ORRI) or a carried working interest from any production that ensues. A typical ORRI for a geologist might range from a minimum of one percent up to one thirty-second (3.125 percent) of the production. All overrides are carved out of the working interest, so Tthe geologist’s ORRI will proportionately reduce the operator’s (and hence the investor’s) revenue interest in the prospect. If the generating geologist also takes a ground-floor working interest, however modest, in the prospect, it affords some measure of assurance that he has a substantial degree of confidence in it's merit.

The second step in the deal is the acquisition of the land—or rather, the mineral lease(s). The operator will send a landman (the noun is always masculine, even though many landmen these days are women) to the county courthouse to find out who controls the minerals within the prospect area. If the mineral rights are “open,” the landman will contact the mineral owners and endeavor to negotiate the terms of a lease. Ordinarily the landman is paid a salary (or a flat daily rate) and does not expect to share in the production, but there are many exceptions. If the minerals in the prospect area are already leased by someone else, the operator may contact that party and attempt to buy the lease for cash or get a “farm out” on all or part of the property. A farm out is a deal in which the party who has leased the minerals allows another party to take the risk of drilling a well thereon in exchange for some consideration (usually an override). That party who drills the well will rarely get more than a 75 percent net revenue interest (NRI) from the lease owner, and that means that his investors will not either.

When a mineral owner signs a lease in Texas (and almost all of the US; most foreign countries are completely different), he gets some cash up front (called a bonus) and a share of any production (a royalty) that may result therefrom. The bonus money, which the operator pays to the mineral owner at the time the lease is signed, may be as low as ten dollars an acre in areas where oil and gas production is highly speculative, or it may be as much as several tens of thousands dollars an acre in an area where good production is probable.

The terms of the lease give the operator a time limit (the “primary term”) in which to begin drilling operations before the lease expires and the property becomes “open” for a new lease agreement. Forty years ago, the most common primary term was five years; today it is three years and sometimes less. If oil or gas production results from even a single well that began drilling operations during the primary term, the lease, or some designated portion thereof, remains in force until there is no longer any production of any kind still continuing on the property.

A typical prospect might involve somewhere between 80 and 800 acres; 400 acres is a very rough average, although, obviously, this figure can vary greatly. Three dozen years ago the standard royalty for the mineral owner in most parts of the US was one-eighth (12.5 percent), but most mineral owners have come to expect at least three-sixteenths (18.75 percent) or a little more, and in some really hot areas they are demanding, and getting, a full quarter. If a deal involves leases where all the mineral owners receive a three-sixteenths royalty and the generating geologist gets a three percent override, the investor will end up with a net revenue interest of:

100% – 18.75% – 3% = 78.25%

Since all the working interests must share whatever fraction of the oil and gas revenues is left after the royalties are deducted, an investor who paid for 10 percent of the working interest in this hypothetical deal would receive 7.825 percent of the oil and gas income (less production taxes which vary by state).

THE INVESTMENT DECISION

No one can predict with 100 percent accuracy whether any given oil and gas prospect will encounter commercial quantities of hydrocarbons. But a savvy investor can greatly improve his economic odds by using a little common sense and professional advice when trying to select a potentially profitable prospect. Here are some easy-to-remember suggestions:

Don’t put all your eggs in one basket. Over an appropriate period of time, take a small piece of several deals in several different areas. Invest in some oil prospects and some gas prospects, some wildcats and some close-in development deals, some shallow wells and some deeper ones, and don’t necessarily spend all your investment dollars with a single operator. Just as diversification is a good strategy for your stock and bond portfolios, so it is for your petroleum investments also.

Most sophisticated investors within the industry would have to be very impressed with the geological features of the prospect before they would agree to a revenue interest any lower than about 77 percent. The very smallest revenue interest that most industry insiders will accept under any circumstances is 75 percent. As a general rule, the prudent investor will at least make an attempt to search out deals in which the revenue interest is no lower than 80 percent, although they are likely to be few and far between.

Okay, so you’re looking seriously at the deal some outfit has pitched you. It’s not unfair to ask “What’s in it for the operator/promoter?”

 WHAT’S IN IT FOR THE OPERATOR?

The operator needs the investor to put up some (or all) of the money to get the test well drilled, but he also has a right to expect to get something out of the deal for himself. That something is commonly called a “promote,” and you, the investor, are the party who pays it. A promote may take any of several forms. The operator may keep an ORRI, especially if he was able to acquire the leases with a relatively high revenue interest to begin with.

A common promote frequently used by reputable operators these days is a “carried interest,” otherwise known as a “back-in.” This is nothing more than a free ride for a percentage of the working interest costs up to a certain specified point in the development of the property, at which time the operator will be allowed to get “back in” to the working interest income and future expenses of the well. In other words, the investor will pay for a certain fraction of the working interest in the first well in his own name plus an additional smaller fraction of the working interest for the benefit of the operator. The terms of the deal will specify one of three points in time when the operator will reclaim that specified fraction of the working interest from the investor. One is at the “casing point,” one is “through the tanks,” and the other occurs at “pay out.”

From the investor’s point of view, the operator’s “back-in at casing point” is by far the most attractive of the three deals. It means that the operator has to start paying his fair share just as soon as the well is drilled to its total depth and logged and the decision is made to set casing in the hole and make a completion attempt. Whether the well ultimately turns out to be profitable or dry, the operator has to begin paying his working interest bills just like everybody else. This arrangement tends to make the operator evaluate the well’s economic potential as objectively as possible.

The “through-the-tanks” back-in is the least favorable to the investor because it almost guarantees that the operator will set pipe  and attempt to complete a borehole that appears marginal (or dry) at casing point. Since the investors are paying for the entire completion attempt, the operator has nothing to lose, and if the well accidentally does make a little bit of noncommercial oil and/or gas, then the operator makes a small profit off of his investors’ tough luck. Only the most geologically compelling prospects should bear a “through-the-tanks” promote. (The gas well equivalent of through-the-tanks is “into the pipeline.”)

In terms of investor desirability, the back-in-at-pay-out deal falls somewhere in between the casing point and through-the-tanks deals. It simply means that the operator is carried through the expense of installing all the surface equipment, but then the investors get to keep all the working interest proceeds of oil and gas sales until they get their entire investment paid back, at which time (“pay out”) the operator starts participating with his agreed-upon share of the working interest expenses. If the well never reaches pay out, the operator gets nothing.

If the investor is satisfied with the net revenue interest he is going to get, he must also take into consideration the back-in and/or carried interest for which he is being promoted. We can quantify that promote with some simple calculations. For those calculations, I very strongly recommend that you see another page elsewhere on this website: HENRY’S LAW OF OIL PATCH PROMOTES.

THE CASING POINT DECISION

Sometime prior to the date that the proposed well actually “spuds” (i.e., commences drilling), the investor will execute a contract with the operator, called an “operating agreement,” that spells out in some detail what the obligations of the operator and all the working interest partners are between and amongst themselves. The investor will also be required to put up all or most of his proportionate share of the estimated expense of drilling the first well to its proposed total depth including running wireline logs. When everyone’s money is safely in the operator’s bank (preferably in an escrow account), the real fun begins.

As soon as the operator commences drilling operations, the investor should be entitled to receive daily email drilling reports to keep him abreast of the drill bit’s progress. Ordinarily, all sophisticated industry working interest partners are responsible for their proportionate part of the drilling costs, regardless of what the operator’s initial cost estimate was or how much money they have prepaid. If the well goes over budget, those partners may be called upon to contribute additional funds to keep the drilling rig going. In that event, a partner who fails to respond in a timely manner may forfeit all or part of his interest in the well back to the operator without compensation.

Most drilling deals are structured so that the operator alone will decide whether or not the information gleaned from the logs and drill cuttings justifies the additional expense of cementing an expensive string of casing in the hole and attempting to coax oil or gas out of the rocks and up to the surface. That process is called the completion attempt, and since it commonly represents almost half of the total expense of the well, it is not a decision to be taken lightly. Sometimes the casing point decision is an easy one, and the operator will not hesitate to run pipe in the hole (or, in the case of a dry hole, plug it and walk away). Other times, the completion attempt is not a sure thing, and setting pipe may prove to be an exercise in throwing good money after bad. Or, as we say, “Welcome to the oil patch.”

In any event, at the casing point the operator will take all the geological evidence into account and make a recommendation to all the working interest partners as to what should be done next.

 THE CHECK IS IN THE MAIL

If the initial test well on the prospect is a dry hole, most investors will have no enthusiasm for financing a second well on that same property. The acreage block will be allowed to expire unless the operator can find some other oil company that wants to purchase it from him, in which case the investors will get their proportionate part of the proceeds of that sale and a few pennies back for their long-gone dollars.

If pipe is set on the first well, the investors will continue to receive daily reports from the operator documenting the progress of the completion attempt. Not all completion attempts are successful, and the well may still turn out to be a dry hole. And even if the well is a good one, the investors should not expect to see a check immediately. In the event that the hole is completed as a gas well (or an oil well with substantial amounts of associated “casinghead” gas) there will be a delay—at least for several days and sometimes for weeks or months—before the well can be hooked up to a gas pipeline.

Let’s assume that the well has been completed as a producer of some kind or another, and now you’re wanting to finally get paid on your investment. What’s really going on when the operator tells you, “the check is in the mail”?

When the well finally goes on production, daily reports usually cease and the operator will hire a lawyer to draw up a legal documen, called a “division order,” which specifies exactly what fraction of the income from the well will go to each and every royalty and working interest owner. This process commonly consumes another few weeks, during which you will receive a copy of the division order to sign and return before you can get paid. But the checks will eventually start to arrive, and the first one is usually a big one that encompasses the first several months’ production.

Proceeds from the sale of oil and gas are generally paid monthly, and they will come to you from either one of two sources, the operator or the purchasing companies that are buying the product(s) from the operator.  If it is the operator himself who pays you, it is common for him to subtract your proportionate monthly well maintenance expenses and state taxes from your gross proceeds and remit a check for the net amount. Alternatively, the operator may turn the division orders over to the oil and gas purchaser(s) and let them send you a check for the gross proceeds less taxes. In that case, the operator will send you a separate invoice for the monthly expenses. Many oil wells in the United States cost very approximately $1000 a month to operate, and most gas wells cost less. If the well is also producing a large amount of salt water that has to be trucked to a disposal facility, monthly expenses can be quite a bit more. Your mileage may vary.

If the first well is a good one, the operator will probably notify the working interest partners that he wishes to drill a second one on the same property. If the investor does not want to commit the funds to drill another well, he may be required to relinquish his interest in the remainder of the property (although, of course, he will retain his full interest in the first well).

There is no hard and fast rule as to what constitutes a “good” well. A 1000-foot-deep well that consistently pumps half a dozen barrels of oil per day would be considered very economical, even in times of depressed oil prices. By comparison, a 10,000-foot well would probably have to start out producing at least 50 barrels a day in order to justify drilling a second well on the property. Obviously, current oil and gas prices play a major role in this qualitative generalization.

Okay, that’s the biggest part of what you need to know about investing in oil and gas drilling deals. Let’s finish up with a few miscellaneous tips and be done with it.

A FEW MISCELLANEOUS TIPS

In no particular order, here are a few random pearls of wisdom pertaining to oil and gas investing in general:

• Serious oil and gas operators never go out and try to drill a good well; they try to drill a good well that has the potential for one or more equally good (or better) offset wells all around it. The serious investor should have a written understanding with the operator that if the test well is successful, there will be enough additional acreage included in the deal for the drilling of at least two or three adjacent wells. The investors in the first well will have first right of refusal for all subsequent wells in this prospect area of interest (AOI).

• Beware of overly simple deals in which you are approached by someone brandishing a small lease map with nothing more than a colored outline on it. A legitimate prospect will always be presented by one or more industry professionals who have taken the time to prepare a comprehensive (and comprehensible) brochure that contains maps, several pages of text describing the geology of the immediate area, nearby (and presumably analogous) production data, etc. The brochure should also contain a copy of the proposed terms of the deal. If you end up taking a piece of the deal, the brochure is yours to keep; if not, industry etiquette requires you to return it.

• That said and understood, a slick and fancy brochure is no guarantee that the prospect has any geological merit. Your best bet is to hire a consulting geologist for a day or so to evaluate the information the operator has furnished you and to render an opinion. For a small fee, you may save yourself many thousands of wasted dollars.

• Beware of “hot” deals that have a short fuse. If you have to put your money up by the end of the week in order to get in on a “can’t miss” prospect that is about to spud any day now, forget it. This is one of the oldest come-ons in the book.

• Don’t be in too big a hurry to spend your oil and gas investment money. Industry insiders ordinarily expect to participate in only about one out of every 10 to 20 unsolicited prospects that are submitted to them. You should be discriminating with your funds as well.

 • Assuming the first well hits and there is acreage already under lease for additional offset wells (refer to paragraph immediately above), the investor should not be promoted on any of those additional wells. After the first well is drilled on any given prospect—whether it’s a gusher or a dry hole—any and all subsequent wells drilled under the terms of the original deal are strictly “heads up” (i.e., at actual cost only) for all the originally involved investors. Now, if your operator has another deal for you on the far side of the county, that’s another thing altogether, but on any given prospect you pay your entire promote on the first well only. Period. Under no circumstances should the investor be charged a larger promote on subsequent wells.

• If you, as a layman of normal intelligence, can not read the prospect brochure in the privacy of your own home or office and understand the basic geological idea of the prospect, then you don’t need to be investing in it.

Needless to say, all the usual caveats apply. Before you sign any contracts, you might let a lawyer look over them for you, and before you write any checks, you might want to consult with your accountant or tax advisor.

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