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Like people, oil and natural gas wells have productive lives—they are born, decline over a period of time, then are put to rest. Also like people, the length of their lives can be affected by a variety of circumstances, both physical and economic. Ultimately, however, all wells reach their economic limit and can no longer be profitably maintained. They are then “plugged and abandoned.”
Of course, many wells drilled with high hopes turn out to be “dry holes.” In some of these, anticipated reservoir rocks are not present, are filled with salt water, or are too dense to allow passage of fluids through their pore spaces or fractures. Soon after the well reaches its targeted depth, such wells are filled with mud and cement and are sealed.
Wells that are deemed potentially productive are “completed,” a process in which protective steel pipe (known as “casing”) is cemented in place to prevent the hole from collapsing—safely protecting fresh water zones behind steel and cement and isolating gases and fluids contained in the various layers of rock. Perforating the pipe opposite the targeted formation allows oil to flow into the well bore where it can be brought to the surface and sold.
When wells are new, oil and gas entrapped in rocks nearest the wellbore are the first to enter, and production rates are high. As oil and gas are produced and reservoir pressures decline, fluids must move greater distances to reach the wellbore. Initial production rates may decline rapidly, sometimes as much as 90% in the first year, depending on the characteristics of the fluids and their host rocks.
Generally, after several years, production rates stabilize at lower values and future well performance becomes more predictable. All wells will continue to decline, but the rate of decline may be so gradual that the well may continue to yield low volumes for many years or even decades. Low rate wells, commonly known as “strippers” because they strip the remaining oil and gas from the ground, typically produce less than 15 barrels per day. Although they produce only about 10% of the total US oil output, stripper wells comprise 80% of the total number of US wells. At the end of 2015, there were around 380,000 domestic strippers, down by 19% from 2008. However, strippers still surpassed “non-strippers,” which totaled about 90,000 at the end of last year. These stripper wells are an important component of the economy as they employ thousands of oil field workers, support most of the well service sector, and each month provide income to several hundred thousand mineral and royalty owners.
Much of the imputed value of marginal production is in its “tail”—the long period of time after a well’s flush production has passed, its decline rate has leveled and, hopefully, the well has recovered its cost of drilling and operation. At such point, operational expenses are generally low and settled, and the operator can typically expect the well to continue to generate profits for many years. However, a sudden and significant decrease in oil prices or an increase in operating expenses will shorten the well’s economic life and truncate its projected future net revenue.
Five States and our investment partners are not totally immune from these problems. We own interests in many producing properties that are at or near their economic limit. We routinely review all our properties to “keep our garden weeded,” eliminating unprofitable properties that have little potential future value, but continuing to hold those that may prove more valuable in the years ahead.
As a well reaches the end of its economic life, operational expenses eventually overtake profits and the owner’s previous asset becomes a potential liability. The margin between profit and loss can be excruciatingly thin and is almost exclusively determined by daily oil prices.
Consider the situation in which the expenses of a well’s maintenance is equivalent to $40 per barrel (i.e. $40 oil is required for the well’s owner to “break even” each month). If the price increases to $45, the owner makes a profit of $5 per barrel; at $35 per barrel he loses $5. In other words, an owner of marginal properties must be willing to place a bet each day: continue operations with the expectation (or hope) that prices will eventually move higher, sell as soon as possible, or plug and abandon immediately.
Alas, such a decision is not a simple one. If he sells or plugs his wells, and prices suddenly turn upward, he has lost the opportunity to participate in what could be a bonanza. Because operating expenses are fairly independent of oil prices, small fluctuations in prices can result in significant leverage on profits. Every dollar above break-even drops directly to the bottom line. If prices suddenly plummet, as they did last year, an owner’s pain increases as he must “feed the kitty” for an indeterminate period.
Even though a well is producing at a loss, the owner likely realizes that it still represents a potential asset. Even after most reservoir pressure has been depleted and his production has declined to the economic limit, as much as 85% of the original oil in place (“OOIP”) still remains in the reservoir. Could a portion of the remainder be recovered by other means (e.g., water-flooding or the like)? Equipping his wells for such processes is time consuming and expensive, and may ultimately prove unsuccessful in the long run. If he is not well financed, where would he get the required investment capital?
The owner also knows that there may be other zones, perhaps deeper, that could be later drilled and exploited on his leased acreage. Is it worthwhile holding the leases by production until he can find companies who would finance the expenses of exploration and development, and provide additional value to him?
Even if he decides to plug and abandon his wells in order to eliminate expenses, or the state’s regulatory agencies require him to do so, he is not out of the woods. The expense of plugging and abandoning a well is likely to be greater than the value of recovered equipment (i.e., the “salvage value”). The owner may have to borrow funds from a bank or other source just to stanch his losses.
If he has already borrowed from a bank to drill new wells or fund operations, his problems are exacerbated. His loans may be collateralized by hedges placed during a time when oil prices were higher. Their value may be burning off monthly, making his collateral worth less than his loan, and leaving him unable to make principal and/or interest payments.
This is the situation of many individuals and companies in the oil business today: underwater, cash strapped, frustrated and scared. It is a common and unfortunate malady that seemingly occurs about every 10 years or so in our industry.
Financial theory is based on the assumption that money has “time value”; that a dollar in hand today is worth more than a dollar received in the future. For example, if you have a dollar today and use it to buy a CD paying 2%, the CD will be worth $1.02 in a year. Stated conversely, the present value of $1.02 to be received a year in the future is worth $1.00 today if the interest rate (the “discount rate”) is 2%.
The concept of a discount rate is used to value the projected future income from producing properties. The discount rate is the expected rate of return. A buyer calculates the expected yield into the price they are willing to pay for a producing property.
In the following example, I have assumed our target return (a discount rate) of 10%. If we expect to receive $5,400 in income over the next three years, we are willing to pay $4,508 for the property. We would earn $892 in profit ($5,400 of income on a $4,508 investment) which calculates to a 10% return, without prices increasing.
|Present Value of a 3 Year Annuity|
|Barrels Produced||Income/ Barrel||Income Received||Present Value @ 10%|
|1||100||$ 20||$ 2,000||$ 1,818|
|2||90||$ 20||$ 1,800||$ 1,488|
|3||80||$ 20||$ 1,600||$ 1,202|
|Total||$ 5,400||$ 4,508|