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In Part 1, I covered Bakken differentials and how it could be a good year for refiners using it as a feedstock. We recently saw Bakken/WTI differentials widen from $4/bbl to $11/bbl. Most are reporting estimates of $11 to $13/bbl in 2014. These differentials will cut into operator profits, but pad development will aid in lowering costs. Fewer rigs are needed as operators are drilling and completing wells in a shorter period of time. Operators are also testing new completion designs that significantly outperform results from just a year ago. Differentials may not be too detrimental as I don't see it widening much in 2014.

Bakken producers should have another good year, but focus on good investments. A consistent operator is the most important. One bad well result can cause a considerable pull back. Operators that consistently beat production guidance do so on a great well design. The problem with determining whether well results are good is time. Not only does one have to find and go through all of the operators' well results, but also those around that specific well.

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Obviously, wells in Divide County will not produce like those in Mountrail. Sweet spots like Parshall and Twin Valley fields will out produce most if not all. These better areas have more appealing IRRs, so the oil price needed is much lower than average areas. The above map identifies middle Bakken thickness, and also shows where the best areas are. The darkest area runs along the Nesson Anticline and is considered to be very good areas. This is also affected by downspacing. We are finding North Dakota is producing a much larger number of location per square mile.

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Downspacing is probably the most important reason to be bullish the Bakken. There are currently three identified economic intervals throughout the core area of the Bakken. There are up to five targets, but the third and fourth benches of the Three Forks are still being delineated. Three Forks' thickness is also important. Below I have provided a Three Forks thickness map.

When we take the middle Bakken isopach and compare to the Three Forks group, we find both are good in roughly the same area. What is more important is the area the Three Forks covers. When shale thickness is considered we find why the Three Forks has upside. The orange colored area is 250+ feet, but is to the south and west of the thickest middle Bakken interval. This is not as important as the green areas are still 200 feet thick, while the light orange is between 225 and 250 feet. This provides ample opportunities for tight well spacing. Density pilots are being done throughout the play. Some are being watched closely while others aren't. The map below provides this information.

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Continental (NYSE:CLR) is doing the most to delineate the play, throughout its intervals. The Wahpeton pad is a focal point, and I believe could drive acreage values in northwest McKenzie County. This provides 660 foot spacing between interval locations. It provides the same spacing from each interval.

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Continental has stated its Wahpeton pad is progressing as planned, but a more bullish indicator is three additional tests planned near the Nesson Anticline. This includes Lawrence, Mack, and Hartman. These pads will test 8 wells per interval from the middle Bakken to the third bench of the Three Forks. The first results from the Hawkinson pad tested 1320 foot spacing and had excellent (my opinion) results. This was a 14 well pad, but 3 wells were already existing, the other 11 were completed after. Over the first 24 hours, these wells combined to produce 14850 Boe. I would expect future wells will produce better as Continental gets more comfortable with pads this size.

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Whiting (NYSE:WLL) is also downspacing in the Bakken, and is having good success. The picture above only begins to show the speed at which Whiting is tightening locations. The map below show where each of the above prospects are. The map below also provides the location of Whiting's recent acreage acquisition. This is important as the area may have significant upside with respect to well spacing.

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This is important to acreage valuation. Other operators drilling nearby will benefit from the results in North Dakota and Montana. The Missouri Breaks prospect includes these areas. Whiting now estimates it can have four additional middle Bakken infills. Including the upper Three Forks it will support 11 wells per section. Hidden Bench Prospect is to the east of Missouri Breaks. Its newest acquisition connects these prospects. The geology improves here, and Whiting is downspacing more aggressively. The middle Bakken may provide 8 locations and the first bench of the Three Forks 7. The Sanish Field is seeing the testing of 7 middle Bakken locations and 3 in the first bench (upper) of the Three Forks as a comparison.

Oasis (NYSE:OAS) has currently de-risked its acreage to 4 middle Bakken and 4 first bench locations per mile. It believes this spacing can be tighter, resulting in 6 wells in each of the 4 intervals. It doesn't include the fourth bench as this isn't uniform, and will probably be a focus around the Nesson Anticline. It is not surprising that North Dakota and Montana can see mega-pad type development. It is a surprise how quickly this has occurred.

Well design will continue to increase IP rates and EURs. 2013 was a big year, as operators experimented with differing designs as well costs headed lower. Well costs continue lower, even as operators use longer lateral, shorter stages, and more water and proppant.

Decreasing Bakken Well Costs

Operator201220132014 est.
Continental9.287.5
Hess (NYSE:HES)13.47.8

The above table covers the well costs for two of the largest operators in the Bakken. This is the trend for all of the Bakken names. Smaller operators are experiencing the same thing, although its costs are generally higher.

Well design will be a popular topic in 2014. Some operators have decided to stick with what has worked, while others are testing out new and different completion methods. Slickwater fracs have been used more in west McKenzie and Williams counties. I covered this frequently last year, and it has shown promise. Slickwater fracs have always provided good results, but well costs pushed operators to other completion styles. Early in development, there were water shortages throughout North Dakota. Back then, there weren't enough industrial water permits in play to sell to the oil companies, which increased water costs significantly. Since then, a large number of agricultural water permits have been converted to industrial. This has made water much more affordable, and easily obtained near the well site.

Emerald (NYSEMKT:EOX) is a new Bakken operator that has employed the use of slickwater fracs with very good results. Its first three completions used an average of 4 million pounds of proppant and 240000 bbls of water. Kodiak (NYSE:KOG) recently purchased Liberty Resources. It has also used slickwater fracs exclusively in its western Williams and McKenzie leasehold. Below is a list of those wells and its design.

WellLateralStagesWaterProppant
2119810429352623063838339
211979144352550513806161
207489240321925802948196
2206710486352562974129852
220689359352503274103810
214819102352412344059653
215789881352246323774597
224959986352432504095724
211419777352489774070072
225229886352481034101909
216809427352527883906420
224019675352477414122587
231329816352402914111530
233989961352454814074751
232019337352455954156300
234239475352458264035679

Kodiak was willing to pay a premium of Liberty's wells and acreage, as the results warranted the cost. The results below, show how important slickwater fracs have been in the western Bakken.

WellDate30-Day IP90-Day IP
211984/121032754
211974/12821628
207485/12511412
220676/12645493
220686/12431419
214817/12866656
215787/12317285
224958/12860613
211418/12827565
225228/12718631
216809/12656543
224019/12699486
231329/12851611
2339810/12772496
2320111/12638520
2342312/121190854

It is very important to understand how western Williams and McKenzie counties have evolved in 2013. On August 1st of 2012, Halcon (NYSE:HK) purchased GeoResources. This acquisition included operated western Williams County acreage. Development had already begun, but results were unimpressive. The middle Bakken is shallow here, which provides lower well costs. IP rates were very low as well pressures increase at greater depths. It was initially thought these well weren't economic. In reality, they model differently with a much lower rate of depletion. Halcon has improved this design, which has helped increase recoveries.

Oasis has an impressive Bakken leasehold. It has acreage both east and west of Nesson. It has been very active in western Williams. Oasis has been responsible for a good amount of development in western Williams.

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The picture above highlights the large acreage purchase by Oasis last year. Its acreage purchase east of Nesson fit well with its current leasehold, but isn't as important as west Williston. Increased activity in this area points to Painted Woods, Indian Hills and Foreman Butte being a stacked play with further possible downspacing. Part of this acreage is prospective to the lower Bakken Silt. This plus additional thickness in the middle Bakken and upper Three Forks. Whiting believes much of this area will support 15 wells in just the top two intervals. The lower Bakken silt (as seen in the Williston Basin Primary and Prospective Drilling Plan By Area Image above) is its own interval, but operators are fracking into it as opposed to drilling the silt directly. During the second half 2013, Oasis used a standard well design.

WellLateral Ft.Stages Ft.Water Bbls.Proppant Lbs.

IP30 Bo/d

IP90 Bo/d

IP180 Bo/d
217211015336805704090462633424347
21314994736741974003952489388324
23988960436594833239158379255242

Stages are a little tighter on average, as the average well design uses 300-foot stages. 70000 to 80000 bbls. of water are generally used on long laterals. Oasis' use of 4 million pounds of proppant also falls within operator averages. The well design is important as it shows the importance of proper amounts of water and proppant. Both well 21721 and 21314 have 180-day IP rates significantly better than well 23988. All three wells are in the same field, and relatively close to one another. The geology is comparable. Well 21721 produced 62460 bbls of oil. Well 23988 produced significantly less at 43560 bbls. Using $90/bbl. as the realized oil price, the first well will produce $1.7 million in revenues over the first 6 months. Oasis does use a fairly large choke, which allows the resource to flow with less resistance. Due to this, depletion rates will be higher when compared to other operators.

Triangle Petroleum (NYSEMKT:TPLM) has come a long way from a non-operated producer. It is now an operator, and has its own midstream and completions business. This has provided better control of its locations, and more importantly better margins. The table below provides some of Triangle's locations, well design and results.

WellFieldStagesWaterProppant

IP 30

IP 90IP 180
23775Ragged Butte31719743561229515407328
23777Ragged Butte31742753826324497421328
23432Antelope Creek25510263108051334260206
23812Antelope Creek31684303854806593406321
22625Antelope Creek31831964209224517376302
22627Antelope Creek31818354164503416317259
24027Antelope Creek31770023253844376319247
24664Antelope Creek31730283892538534382
24665Antelope Creek31769083942852476339
22297Otter28690623569288231188170
22296Otter31632344093148370244238
23114Buffalo Wallow31796443863719479338261
22096Ellsworth31773283903588347239194
22097Ellsworth31783263923541491356279
21632Ellsworth31766013731458665437354
21452Pronghorn31709823272518430364275
21825Rawson31676403956579349279273
21827Rawson31644433605222395334312
23160Rosebud31627393787154579391302
22558Rosebud31637533803450560415342

Triangle has used a standard well design. It does use varying amounts of ceramic proppant and averages 3.5 to 4.0 million pounds per long lateral. Triangle's were the best results in the area until we started to see slickwater fracs. Triangle has and continues to do an excellent job of stimulating the source rock. I am unsure how it accomplishes this, but would guess it has to do with the number of perforation clusters per stage. Triangle has continued to decrease stage length well below the 300-foot average. It continues to produce excellent data.

In 2013, we started to see an evolution in completion design. In the past, we had tried to stimulate source rock fractures long and deep into the formation. This initial perception was correct, as completion designs improved and produced large voids that spread out like tree branches. There were initial worries that these induced fracs would commingle causing the wells to stop producing. This hasn't been a problem, but the issue at hand was increasing total surface area exposed to the well bore. Using more hydraulic horsepower to create even longer fractures was self defeating. The longer the fracs, the more difficult it is to get the proppant to its furthest point. Many times these long fracs didn't produce consistently throughout. EOG Resources (NYSE:EOG) initially developed what I believe will be the U.S. completion standard. It changed focus to fractures closer to the well bore. This was important, as it was able to create more total surface contact with the well. More surface area equals more recovered resource, and this is a game changer.

The table below provides the well design of EOG wells in Parshall Field. The production rates are impressive, but more important is the depletion rate. By focusing closer to the well bore and using more proppant, well results improve dramatically.

Parshall Field

WellChokeLateralStagesH20ProppantIP 90IP 180IP 270
2137824/64647532798556867099793784673
2278032/64891638993169438324786770678
2123930/647873421068879023010110110821072
2209132/64102775011211410369690747694622
2270444/64106625315390010927550761633
2270344/64681034933606972110748616
2063348/64967249142457106908601054932
2292148/649101491393701053056714081186
2140648/641029653170645136239421168
2428128/649901491369361017826013831298
2376340/641246462168459124319411387
2376440/641112155143806108802591542
2268948/641099954155204111739901047

Whiting was the first to duplicate or replicate EOG completions in the Bakken. Its older completions utilized sliding sleeves with free fluid between packers. Sliding sleeves are limited to one frac port per stage. This basically means there is only one opening over that space to creates fractures in the source rock. The new design uses a cemented liner. Whiting is able to use three perforation clusters per stage, which effectively triples its ability to frac the interval. Improvement in 90-day cumulative production have ranged from 55% to 97%.

There are several ways to play the Bakken in 2014. Looking at the operators, some caution should be exercised as differentials could widen. There are other factors I emphasize as important, when shopping these names. When picking Bakken operators, values will be levered to downspacing. It is not necessarily the operators with the best acreage, but the acreage with the most upside. Operators in central to northeast McKenzie County could see as many locations as the best parts of the play. Keep in mind, EURs will not be as good on a per well basis. I would stick with names levered to these areas. This includes Oasis, Whiting, Triangle, and Emerald. Whiting has further upside as it is using an optimal well design and one that still can improve. Emerald's slickwater fracs have also outperformed and seem well suited to this specific area. Triangle and Oasis have further upside as its integrated model provides cost containment.

Source: Bakken Update's 2014 Bakken Stock Picks: The Bakken Operators