I'm publishing this article to help new analysts like myself understand the economics of well production and revenue more clearly. My last article was written on the costs associated with drilling a well before production, so this is a follow-up to the cost article.
Source: Energy Landscapes
To understand an exploration and production or E&P company's revenue, we must start with understanding that revenue is equal to the Price multiplied by the Quantity. For oil and gas production, the price received for production is set by the market. The combination of oil, natural gas, and natural gas liquids or NGLs recovered makes the production mix. Differing production mixes creates different prices exploration and production companies recognize for each barrel of oil equivalent or BOE sold. Most companies publish their production rates with the BOE which is determined by having 5.8 million Btus or British Thermal Units of energy. A barrel (42 gallons) of 100% oil has the amount of energy necessary for one BOE. Natural gas is recorded in Mcf or thousand cubic feet. For a barrel of 100% natural gas, 5.8Mcf is needed to reach the Btu figure. Natural gas is listed on a MMBtu basis and is selling for around $3.30/MMBtu. Since one BOE needs 5.8MMBtu, the price of natural gas must be multiplied by 5.8 to come to the price received. This means that a barrel of 100% natural gas sells for $19.14. In a world where oil sells for a little above $50 per barrel, one can see that a barrel of 100% oil is worth over 2 times the price of a barrel of 100% natural gas. Natural gas liquids are valuable when separated and can be separated from natural gas in processing plants. Examples of natural gas liquids are propane, ethane, butane, and more. Each natural gas liquid sells for a different price, which makes calculating exact revenue from each well difficult. Some analysts assume two-stream production by combining natural gas and natural gas liquids and pricing the combination at the price of natural gas. In this case, the two streams would be oil and natural gas equivalent.
The next factor in price received is the hedge positions of producers. Producers can sell oil deliverable on certain dates in the future through futures contracts. Oil producers can lock in revenue numbers before oil is even extracted from the ground this way. Futures contracts allow E&P's to mitigate the risk of declining oil prices. It's important to note a company's hedge position because a portion of their revenue is already accounted for, and when hedged correctly, E&P's could sell their oil for higher than current market price. Of course, they could end up selling their oil for less than the market price as well.
For oil and gas, acreage can predict production mix. Certain regions demand different multiples where the trend is oil-heavy or gas-heavy. Delaware Basin acreage sells for high multiples as I covered in my Centennial Resource Development (NASDAQ:CDEV) article. The estimated ultimate recovery metric becomes relevant when determining which acreage is the most economical. If natural gas, albeit cheaper to sell per BOE, is abundant in a region and the EUR is high enough to cover the costs of drilling and completing the well, there is reason to purchase and produce on acreage in a gassy region. Since oil sells for a higher price on the market right now, the EUR for a well on oil-heavy acreage doesn't have to be as high to make drilling a well economical.
Another reason acreage may demand a higher multiple is if the geology implies more than one pay zone, or the pay zones are thicker than average. In the Delaware Basin, both factors hold true, as seen in the WPX Energy (NYSE:WPX) slide below. WPX Energy shows 11 proven productive zones on their acreage. In the oil downturn, a lack of revenue made exploring into new pay zones a tough feat, but as oil rebounds, investors will have a better idea of the productivity of the zones outside of the proven zones, such as in Wolfcamp C or 3 rd Bone Spring. Although WPX has proven reserves in most of the 11 pay zones, other producers aren't so quick to recognize the potential. Centennial, for example, has only labeled Wolfcamp A, B, and C as producing zones, with all other zones listed as potential. Acreage prices will naturally increase as well locations per acre increase, and could increase further if other zones are anywhere near the quality of the Wolfcamp.
One concern with oil and gas production is when there is a lack of pipelines and transportation infrastructure. On acreage where this is the case, natural gas may be burned to help protect against the dangers of over-pressuring industrial plant equipment. This burning is called flaring. The margins on gas are lower, so if the pipelines aren't in place, then burning the gas is cheaper than transporting and selling it. Wells can't produce to their fullest potential in an environment with limited infrastructure. In production zones like the Permian Basin, the infrastructure is already in place for transporting oil and gas which draws higher prices for acreage.
Source: Investor Presentation
Estimated Ultimate Recovery
Once the production mix is determined to help determine price, the quantity is the variable in question. The quantity of oil and natural gas being recovered from a well is measured by barrels of oil equivalent or BOE. Companies show oil and gas recovery with type curves. The type curve below shows data points from two of Parsley's wells compared to a type curve with an estimated ultimate recovery or EUR of 880,000 BOE.
Source: Investor Presentation
The type curve shows cumulative production over time. Well production slows down over the life of the well, so the slope of the line decreases from left to right. The slowing of production is referred to as the decline rate. The lower the decline rate, the slower the well will go from initial production rates to more steady and significantly lower production rates. The decline rate may have more of an impact on the overall economics of the well than the price of oil and gas on the market depending on how efficiently the oil is recovered. The cumulative BOE expected to be recovered from a well is represented by the estimated ultimate recovery or EUR.
Type Curve Considerations
When looking at a type curve there are multiple factors to consider. No investor presentation wants to look like they're underperforming, so the EUR of the type curve in comparison is important to note. Some graphs will have comparisons to type curves with EURs of over one million BOE, like Apache Corporation's (NYSE:APA) graph on page 18 of their Q3 earnings supplement. This type curve has a comparison to 880,000 BOE to seemingly "beat the average". Another factor to consider is the unit on the vertical access. Parsley uses MBoe as their unit, yet Centennial uses MBo as their unit. It's tougher to compare a type curve with two or three stream production to a type curve of a single stream. As production matures, wells typically produce a higher percentage of natural gas. This trend will cause a type curve only showing barrels of oil to decline much faster than a two or three stream production type curve. By no means is one of the units better or worse, but being aware of the subtle distinction can help investors. The third factor I've noticed to pick up on is what the laterals are normalized to. By normalizing well results from longer laterals, the efficiencies of longer laterals can be confused with the efficiencies of a new completion design. If a 10,000' lateral is normalized to a 5,000' lateral, an increase in production on the type curve may be from efficiencies realized from a longer lateral, and may have nothing to do with the completion design or location of the well. Below, I will cover how longer laterals effectively produce a higher BOE/1,000' of lateral.
Lateral Length Impact on Production
The recent trend towards longer laterals in the Permian Basin of Texas is due in part by more perforated coverage on longer laterals. Resolute Energy (NYSE:REN) reports 12% more perforated coverage on one 10,000' lateral than two 5,000' laterals. As I discussed in my prior article on well costs, longer laterals diminish the importance of the vertical well costs. Since the vertical well is a fixed cost, the longer the lateral lengths get, the less significant the vertical well is (per foot) on the overall cost of the well. With more production and less cost on the second 5,000' of a 10,000' lateral, more E&P's are looking to utilize these longer laterals. The biggest setback to drilling laterals of almost two miles is that the oil company must own significantly contiguous acreage to drill this long of a lateral. In turn, this increases the value of contiguous acreage.
Resolute Energy posted the production results from their most recent nine wells in their November presentation and the longer wells are producing higher IP30's. I will use these well results because they are in the same region (Delaware Basin) and completion design will be relatively similar since they were drilled by the same company. When you break it down, the average Appaloosa well had an average lateral of 9,322' and the average Mustang well reported had a lateral of 7,482'. The Appaloosa wells have IP30's 72% higher on average. To see how efficient the longer laterals are we can break down the IP30 per 1,000ft. of lateral. The average Appaloosa IP30/1,000ft. is 284.5 BOE, while the Mustang wells had an average of 206.6 BOE. This represents a 33% increase in BOE/1,000 ft. for the longer laterals.
The decline rate on the Appaloosa wells is also lower than the decline rate on the Mustang wells from my calculations. For my calculations, I calculated the wells' actual production from the averages provided and then found the average monthly decline over the period for each well. With higher IP rates and a lower decline rate, the longer laterals produce more BOE just as Resolute said in their presentation.
Completion Designs Improving Well Performance
Upstream oil companies are still designing better completion designs for Permian and Delaware wells for maximum recovery of oil and gas. Below, is Centennial's progress in completion design and a type curve showing improvement.
Source: Investor Presentation
Slick water fluid is increasingly dominating the completion design. According to Rasool Mohammad, CEO of Select Sands (OTCQX:SLSDF), "all operators are using slick water completion method, and it uses finer grade sands such as 40-70 and 100 mesh". The proppant used in the current design is more fine than the legacy design. The 100 mesh proppant can withstand more pressure, and is more expensive. The 40/70 RCS is more fine than the 30/50 as well. As you can see from Centennial's type curves, the recent design has recovered more oil and declines slower than the legacy design. After 90 days, 20,000 more barrels of oil had been recovered with the recent design. The footnotes state that these results don't include longer laterals over 5,000' so the improvements are comparable. The completion design is positively affecting oil recovery, since the type curve is only accounting for single stream production. The graph doesn't show the current design type curve. I would guess that the newer type curve would be steeper and level off slower than the recent design.
Another way to boost production on a well that is already producing is by refracturing a previously drilled well to reinitiate production. The refrac gives a boost to oil and gas production before going back to slightly higher late-month type curve levels. A rendering of a refracture from Halliburton is below.
As you can see, the rock is fractured in more places, and the existing fracture points have deeper fissures after the refracture. The finer sands discussed earlier will dig further into the rock and allow more oil to pass through into the well. Now that more surface area has access to the well, the type curve levels off at a higher level than before as the well matures.
Production from wells is important to understand because acreage can be valued based on the production of other wells nearby. Geology plays a large part in how wells will perform, so finding companies with acreage in the most productive regions can lead to lucrative results. It is important to pay attention to the completion design, because if wells can be further improved from a better completion design, then previous well results may only be fractions of their true potential.
Below is an oil productivity map from Centennial's investor presentation. The map shows why the management chose to buy Centennial's acreage when they were looking for buyout opportunities under Silver Run. The acreage was decided based on the production of other companies in the region. This further supports claims that historically productive acreage is likely to remain productive due to the underlying geology.
Source: Investor Presentation
Disclosure: I am/we are long CDEV.
I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.
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