Bakken Update: EOG Antelope Well Has One-Year Payback At $50/Bbl WTI

| About: EOG Resources, (EOG)
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Summary

EOG continues to be the top US shale operator in the United States.

In its core acreage, EOG wells still provide excellent returns at today's realized oil prices.

Improvements of well design have been significant even in timeframes as short as one year.

The sudden decrease in oil price has negatively affected all US oil producers, and although we know this, the extent is what is difficult to quantify. Every US play has differing economics, but more importantly, those specific economics can change significantly from one section to the next. Just like core geologies are different, so are the areas outside the core. Since the core of most plays have been developed to much more significant degree, economics are a little more transparent. Once we get outside the better areas, wells are more difficult to model due to a lower number of completions. Because of this, one may have difficulty in determining at what realized oil price a well is still good. More importantly, results are not enough. Well design is important, as is the competency of the operator. These variables are the most difficult to judge, as several wells could be completed over a five mile stretch and have a great variance in outcomes. Something as simple is drilling outside the zone could reduce production by 50%, and as an investor we may not know its operator error as opposed to poor geology. Many times there aren't enough well-results to compare within an area. Because of this, areas can be difficult to rate.

As I have said before, the only good way to judge the economics of an area is to go through specific well results. This includes well design, making sure no problems were seen during the process. By going through these areas, we can judge areas and the companies working them. It will also aid in letting us know which direction to take with respect to investment. With oil heading lower, a conservative investment thesis is important. It is possible some names will go out of business, if we are looking at a longer term price revision by OPEC. We don't know for sure if any companies will go under, but keep in mind that large price revisions are still possible.

I will cover a number of fields and companies over this series and how their well design is either better or worse than competitors, but more importantly the validity of these fields at lower oil prices. This should aid us in figuring out which fields will see more development and if other fields will cease all together. Northeast McKenzie County has turned into a second core area within the Bakken. Middle Bakken results haven't been quite as good as Parshall Field, but lower Three Forks intervals have proved to produce well, which offsets the difference. From a pad development prospective, northeast McKenzie may be better. One thing is for sure, it can continue to produce even at lower oil prices. Keep in mind, Bakken differentials have been around $10 to $11/bbl. It is possible this will increase next year, with our models seeing $13 to $14/bbl.


antelopewellresultseogsplitrock1



(Source: EOG Resources)


Antelope Field is occupied by several operators. The main player is EOG Resources (NYSE:EOG) from a production standpoint. It has produced better than anyone, as its well design better stimulates the source rock. These results have been remarkable. Keep in mind, if EOG can do it, so can anyone else. It may just take some time to duplicate. Halcon (NYSE:HK), Enerplus (NYSE:ERF), Marathon (NYSE:MRO), WPX Energy (NYSE:WPX), Continental (NYSE:CLR), Hess (NYSE:HES), QEP Resources (NYSE:QEP), and Exxon (NYSE:XOM) are all present in Antelope and Clarks Creek fields. QEP's models are listed in the diagram below:


antelopewellresultseogsplitrock3
(Source: QEP Resources)


QEP reports EURs over 1000 MBoe in both the middle Bakken and upper Three Forks. This is an area of exceptionally high pressures, due to higher natural gas content in the wells. It is located to the east of the Nesson Anticline. The tables below are wells completed by EOG Resources in the Antelope Prospect.


NDIC Date 360 Days/bbls 360 Days/Mcf Days Total Production/bbl Total Production/Mcf Sold Total Production BOE
20890 3/12 170742 122525 763 244042 217279 283662
20892 3/12 150719 107261 723 212285 194240 247701
20888 3/12 129492 103230 786 190345 194506 225810
20886 3/12 164122 109551 804 252746 240029 296511
20887 3/12 121298 117730 735 195785 245827 240607
20329 5/13 184293 228347 523 216498 309752 272975
20330 6/13 166687 256567 463 188527 314400 245852
20331 4/13 148893 110889 530 179822 212417 218552
20513 3/13 376342 238898 543 452805 398833 525525
*22485 1/13 413440 158458 375 422700 182998 456066
*22487 12/13 283 346460 685516 466528

The above wells are all completed by EOG and in Clarks Creek. Although not in Antelope Field, it is still part of EOG's Antelope Prospect and only a few miles to the northeast. As you can see results have increased significantly from 2012, and the newest well produced 346460 bbls of oil in just 283 days. There isn't enough production time to figure an IP 360, but still we could surmise this well will be 400000+ bbls of oil at that time. The natural gas data is for Mcf sold, and not produced. There are large volumes of gas still flared and this also hurts well economics.

To validate the economics of this specific area at today's oil prices, the table below provides the revenues produced by each well at specific oil prices. The first is well 20890.


WTI/Bbl Bakken Light/Bbl 360 Day Oil Revenues 360 Day Gas Revenues Total Days of Production Total Oil Revenues Total Gas Revenues Total Revenues
$100 $87 $14854554 $490100 763 $21231654 $869116 $22100770
$75 $62 $10586004 $490100 763 $15130604 $869116 $15999720
$50 $37 $6317454 $490100 763 $9029554 $896116 $9925670

As you can see this is an exceptional well at $100/bbl WTI, and still produces very well at $75/bbl. Once we get to $50/bbl, as one would expect, economics get a little cloudy. What is important to note is the revenues generated at $37/bbl Bakken light pricing. In two years this well almost produced $10 million in revenues, and does prove these wells are economic, even if prices are pushed down considerably. I used $4/Mcf pricing for natural gas.


WTI/Bbl Total Revenues Payback (Estimated)
$100 $22100770 18 months
$75 $15999720 24 months
$50 $9925670 4+ years

The well economics change significantly, even in an area as good as Antelope. Keep in mind, this is an older well and designs have improved along with production.


antelopewellresultseogsplitrock4
(Source: Whiting)


With WTI at 100/bbl, this well has a payback of less than 2 years. I didn't break it down to a specific month, but at an $8 million well cost it has a payback of roughly 18 months. At $75/bbl, the payback is about two years. At a $50/bbl price, payback hasn't occurred at two years. Currently well models show this well will not pay back in four years. The above well is a standard type well completed in early 2012. This is not indicative of current well designs and how they produce. Well 20890 was a 22 stage frac, using 64000 bbls of water and 4 million pounds of sand. EOG's newer frac jobs are significantly better.

Well 20513 was completed in 2013. This well produced much better. This isn't surprising as EOG hasn't worked this area a lot, and is still getting comfortable with the geology. Newer wells are producing much better, but the issue with identifying this change has to do with time. Wells completed in 2014, won't provide meaningful results for 12 months. I know some believe that all you need is the IP 90, but this isn't true. Newer wells that do a much better job of stimulating the source rock will deplete at a much slower pace. Because of this, it can take a year to show how meaningful this is. Wells that are stimulated better have more fracs. This increases the surface area that has access to the well bore, and because of this will produce more resource. This production does not all occur immediately, as it is spread out over a greater period of time. We are always chasing production data, so keep in mind improvements are already occurring. A good example of those improvements is seen in well 20513.


WTI/Bbl Bakken Light/Bbl 360 Day Oil Revenues 360 Day Gas Revenues Total Days of Production Total Oil Revenues Total Gas Revenues Total Revenues
$100 $87 $32741754 $955592 543 $39394035 $1595332 $40989367
$75 $62 $23333204 $955592 543 $28073910 $1595332 $29669242
$50 $37 $13924654 $955592 543 $16753785 $1595332 $18349117

These numbers are substantially better than results year over year. This well is a 49 stage frac using 117000 bbls of water and 9.8 million pounds of sand. As you can see, the better source rock stimulation has a big effect on production. The increased fractures require more sand and water. This is why the volumes were so much larger in this well.


WTI/Bbl Total Revenues Payback
$100 $40989367 4 months
$75 $29669242 7 months
$50 $18349117 12 months

The revenues generated from this well are significant. It produced double that of the first well and accomplished it in 220 less days. When we back out costs, we find at $100/bbl WTI it has a payback of 4 months. At $75/bbl WTI the payback extends to 7 months, and at $50/bbl it's a year. The most interesting aspect of this well is it doesn't begin to deplete until the 5th month of production. After 20 months, it is still producing over 10000 bbls. of oil per month, compared to the approximate 50000 bbls. produced during the first 30 days. In month 12, it produced 18000 bbls. of oil.

In summary, although older well designs do not produce excellent results at today's oil price, newer wells are performing much better. We have heard many different estimates as to what oil price is needed to support well economics in US plays, but these are too general and usually are incorrect. Every play has differing geology, and because of this, economics can change from one mile to the next. A Bakken well can be drilled and produce 350000 bbls of oil in the first year, while another well drilled 20 miles away could be identical in design and produce only 200000 bbls. If we see low oil prices for an extended period of time, knowing where the good areas are will be very important. Operators without core acreage will have a very difficult time staying in business as it will not have any acreage with economic wells. We continue to be conservative in how we look at oil producers, as we think oil prices will continue to head lower. This data does prove that some producers will be able to hold on even if oil heads appreciably lower from here. It is important to focus on operators in the best areas, as they may perform better over the long term.


antelopewellresultseogsplitrock5

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