Bakken Update: QEP Resources' Bakken Development Could Be Best In Play

 |  About: QEP Resources, Inc. (QEP), Includes: COP, HES, SM, XOM
by: Michael Filloon

QEP Resources' (NYSE:QEP) recent operational update was welcomed by Wall Street. Deutsche Bank (NYSE:DB) recently named it as one of its top ten oil and gas stocks to buy. A Raymond James' (NYSE:RJF) analyst backed his outperform rating as well. On June 5th, Sterne Agee upgraded QEP to a buy from neutral with a price target of $36/share. Analysts are getting excited about the name for several reasons. Its Bakken results are in the spotlight, as we all like big IP rates, but there are better reasons to own the name. The spinoff of QEP's midstream business should provide a higher multiple for its E&P business. Strengthening natural gas prices should also bolster margins going forward.

On August 25th, I covered QEP's purchase of northeast McKenzie County acreage. Helis operated this acreage. Non-operated working interest was split between Sundance (OTCPK:SDCJF), Unit (NYSE:UNT) and Black Hills (NYSE:BKH). There were rumors of other suitors, such as Kodiak (NYSE:KOG). QEP was willing to pay more, and ended up with the leasehold. The core acreage went for $19000/acre, with non-core at $12000/acre. QEP's motivations for this acreage has less to do with the middle Bakken and more to do with the Three Forks. The upper Three Forks in Grail Field has produced better than any other area in North Dakota or Montana. Helis' results were under the radar as a private company. These large IP rates were also consistent over several miles. This is either a very large sweet spot, or Helis' well design is superior to others in the area. Below is a list of Helis' completions in Grail, Croff and Blue Buttes fields.

Well Date 90-day IP (Bo/d) Lateral (Ft.) Proppant (lbs.) Water (Bbls.) SR Total Oil Field
16929 8/08 108 4400 577360 MB 52349 Grail
18448 9/10 1012 9330 2982750 63926 TF1 296589 Grail
17722 1/11 631 7865 2699965 70173 TF1 184980 Grail
19323 8/11 1201 9400 3285650 81925 TF1 368396 Grail
19379 8/11 553 9310 3084129 82803 TF1 157714 Grail
19680 9/11 774 9144 2674660 76942 TF1 217477 Grail
19898 10/11 1033 9456 3330826 78608 TF1 248781 Grail
21052 12/11 632 9371 3109015 79799 TF1 152132 Grail
21054 2/12 868 9221 3166880 78796 TF1 156457 Grail
21437 4/12 860 9392 3593290 89653 TF1 174979 Grail
21465 5/12 1130 9350 3532991 79012 TF1 241123 Grail
20780 6/12 977 9452 3071775 78632 TF1 203708 Grail
21456 7/12 953 9535 3591030 84655 TF1 180954 Grail
22880 7/12 839 9772 3656740 81044 TF1 152206 Grail
22879 9/12 675 9444 3629300 90565 TF1 108857 Grail
18361 7/10 1052 8846 TF1 329516 Croff
19678 5/12 840 3966 1683214 39338 TF1 157185 Croff
22193 10/12 1206 9657 3532980 82166 TF1 167659 Croff
16652 9/07 253 5422 149051 BB
16960 4/08 193 4524 95073 BB
18973 10/10 1181 9078 2902340 65043 TF1 402772 BB
20591 4/12 1101 8359 3410900 75928 TF1 235960 BB
21564 8/12 1248 9046 3535230 78991 TF1 233412 BB
23472 11/12 688 9724 3072200 47208 TF1 100458 BB
Click to enlarge

The above wells in Croff, Grail, and Blue Buttes fields are impressive. Helis has focused on the Three Forks, and proved it can outperform the middle Bakken. As a general rule, the Bakken has produced better than the first bench of the Three Forks. This has been consistent throughout North Dakota. It is possible the Three Forks could turn out to be better. On average, IP rates and EURs have been lower with respect to the Three Forks. As a general rule, middle Bakken wells are approximately 20% better. The Three Forks has seen less development. I believe when operators get more comfortable we will see higher EURs in the Three Forks.

The most important variable of the above table is the total oil produced. In 31 months, well 18973 has produced more than four hundred thousand barrels of oil. This well in on pace to produce 1.1 MMBo. If natural gas and NGLs are included the EUR is 1.4 MMBoe. Helis has 11 wells that will produce around one million barrels of oil using the 90-Day IP rate. Its wells have historically depleted less than other operators, so EURs could conceivably be higher. As a comparison, the table below provides middle Bakken and upper Three Forks data from other operators in Croff and Blue Buttes fields.

Well Date 90-Day IP (Bo/d)

Lateral (Ft.)

Proppant (lbs.) Water (Bbls.) SR Total Oil Operator
19737 1/12 1065 7164 2790810 68476 TF1 220412 (NYSE:HES)
21402 4/12 909 8739 2020901 55433 MB 151463 HES
22311 5/12 671 9246 2636428 63351 TF1 124821 (NYSE:XOM)
22050 5/12 834 9751 MB 225529 (NYSE:COP)
21429 12/12 774 9191 1611809 30784 MB 90629 HES
21985 6/12 989 10042 3234000 81833 TF1 172590 (NYSE:SM)
22376 7/12 980 10035 3199887 83297 TF1 179162 SM
22377 7/12 1001 10113 3143131 81618 MB 160378 SM
Click to enlarge

Although the sample size is not as large as I would like, competitors in this area are getting good results. I only included wells completed in 2012 as this gives a better view of how new wells are producing. There are some big players in this area, as it is located near the Nesson Anticline. This has been home to vertical oil production since the 50s. Hess has been in North Dakota producing oil since 1951. Northeast McKenzie County is part of its core acreage. ConocoPhillips bought into the play when it bought Burlington Resources in late 2005. In December of 2009, Exxon bought XTO. This deal was about natural gas at the time, but its Bakken acreage is the most valuable now.

Helis isn't the only operator in the area with good results. The table above provides positive data for the middle Bakken and upper Three Forks. In 2012, Helis' average 90-Day IP rate was 949 Bo/d. The average from the eight wells by four different operators was 903 Bo/d. This number is a combination of results from both source rock. If these results are broken down into four middle Bakken and four upper Three Forks, it breaks down 880 Bo/d and 926 Bo/d for the latter. The table below compares and contrasts this data.

90-Day IP Proppant/Ft. Water/Ft. Production/Ft.
Helis TF1 949 Bo/d 369 lbs 8.47 Bbls .107 Bbls
Other Operators TF1 926 Bo/d 325 lbs 8.14 Bbls .102 Bbls
Other Operators MB 880 Bo/d 239 lbs 5.92 Bbls .093 Bbls
Click to enlarge

The table above breaks down production by lateral length. I have also included proppant and water as a means of showing how these affect production. Helis' wells produce more crude when compared to other operators in Croff, Grail, and Blue Buttes fields. A direct comparison of the Three Forks shows a direct correlation between increased usage of proppant and water improving production. The Helis wells produce .005 barrels more per foot. This does not seem like much until it is applied to a 1000 MBo well. In this case, it would produce 5000 additional barrels. The majority of this is upfront, with about 40% seen over the first 90 days. When comparing the upper Three Forks to the middle Bakken there notable discrepancy. Production is lower in the Bakken, but so are the amounts of proppant and water used. It is possible that a similar well design would produce congruent results. This is evident in two SM Energy wells listed above. I have compared these wells below.

Well 90-Day IP Proppant/Ft. Water/Ft. Ft./Stage SR Total Oil
22376 980 Bo/d 319 lbs. 8.3 Bbls. 502 Ft. TF1 179162
22377 1001 Bo/d 311 lbs. 8.1 Bbls. 389 Ft. MB 160378
Click to enlarge

The above wells were drilled and completed from the same pad. The Three Forks well was completed 4 days later and with fewer stages. Due to this, 90-Day initial production is better in the middle Bakken well. The Three Forks well has caught up and passed, and now has produced almost twenty thousand barrels more. Keep in mind a well that has a very high initial production rate early, may not continue to produce in this manner. Well design is more important than any other factor in flattening the depletion curve. Geology only becomes more important when comparing two separate source rocks. This is what we are seeing above. At 90 days of production, well 22377 had produced 90090 barrels of oil. In comparison, well 22376 produced 88200. This is a swing of over 20000 barrels in just 170 days. Both wells used closed to the same amount of proppant and water. The difference is in stage length. The average Bakken/Three Forks well uses 300 foot stages. These stages are longer and are not considered as good. Shorter stages provide better source rock stimulation as the pump trucks have a small area to exert pressure. Even with a poorer well design, the Three Forks well managed to outperform. Both wells had a very tight choke, but the Three Forks well could have been affected as it had a 16/64 versus the middle Bakken wells 18/64. The GOR was higher in the middle Bakken well.

The middle Bakken and Three Forks are very thick in this area. Bakken thickness improves to the east around Sanish and Parshall fields.

Click to enlarge

The shale decreases in thickness from 120+ feet in Mountrail County, but is still around 90 to 100 feet. This is offset by higher well pressures. This is caused by two very important variables. The first is a larger resource mix of natural gas. We use to believe that Mountrail County was better because it produced between 92% and 94% crude. Northeast McKenzie produces 78% to 80% crude. The natural gas unlocked from the source rock helps to push liquids up and out of the well. This improves IP rates, and EURs. Northeast McKenzie County also has a greater depth.

Click to enlarge

There is not a huge difference in depth, but it is still 500 to 1000 feet. This in concert with the natural gas mix has produced some very good initial production rates. I believe Northeast McKenzie County is slightly better than Parshall Field's middle Bakken. These wells will produce roughly the same amount of crude, with much higher volumes of natural gas and NGLs. The Three Forks is a different story and looks to be the focal point of McKenzie County.

The middle Bakken shale is one of the best unconventional plays in North America. The Three Forks may be better. The picture below is a Three Forks isopach. QEP's acreage is sitting on a thickness of 200 to 225 feet.

(click to enlarge)Click to enlarge

This is split between 2 to 4 Three Forks benches. The first and second bench are consistent throughout, while some areas have a third and fourth. The economics of the deepest benches are unknown, but could add locations in some of the thickest parts of the play.

The well balanced pay zones in northeast McKenzie County could make this the best in play. The Sanish and Parshall fields have many of the best producing wells in the Bakken. It also has a much higher percentage of crude. Currently the Sanish Field can support up to 7 middle Bakken wells and 4 upper Three Forks. The second bench has had little by the way of development, but it is safe to say this would support 3 wells. Northeast McKenzie County should support 6 middle Bakken, 5 upper Three Forks and 4 in the second bench. There is not enough production data to model the second bench, so I will not figure this into a pad drilling estimate. The table below covers the Sanish Field's middle Bakken/upper Three Forks pad drilling profitability.

Sanish Field EUR Number Crude NGL Nat Gas Revenues
MB 900MBoe 7 92% 6% 2% $571MM
TF1 500MBoe 4 92% 6% 2% $181MM
Pad Totals 1.4MMBoe 11 $752MM
Click to enlarge

In the table above, I have outlined the average EUR for wells drilled in the Sanish in 2012. Using $95 crude, $40 NGLs, and $4 natural gas I have identified an average well pads total revenues. Keep in mind, these are estimates, and should not be used as a universal truth. Every operator is different, so this should be a focus on the geology and what it means with respect to economics. The average Sanish Field middle Bakken well will produce $550,620,000 in crude revenues. It will produce $17,010,000 revenues from NGLs with natural gas accounting for $3024000. The Sanish Three Forks' wells produce $174,800,000 in crude, $4,800,000 in NGLs, and $960000 in natural gas. Northeast McKenzie County has more impressive EURs per well, but the resource is much different. The table below is a comparison to the Sanish Field.

Grail Field EUR Number Crude NGLs Nat Gas Revenues
MB 1MMBoe 6 78% 11% 11% $487MM
TF1 1.3MMBoe 5 78% 11% 11% $527MM
Pad Totals 2.3MMBoe 11 $1014MM
Click to enlarge

In northeast McKenzie County the middle Bakken has larger EURs, but a lower percentage of oil. Crude accounts for $444,600,000, with NGLs producing revenues of $26400000, and natural gas at $15,840,000. Middle Bakken pad revenues are not as good as in Sanish Field. Keep in mind it is much thicker here, and it would not be surprising if we see 8 wells per 640 acres at some point. The upper Three Forks in northeast Mckenzie is much better than in Mountrail best fields. The middle Bakken produces revenues of $481,650,000, with NGLs adding $28,600,000 and natural gas providing $17,160,000. This area looks to be much better than the Sanish on paper. What happens next will depend on how the acreage is developed, and well design improvements going forward. Keep in mind, that the second bench of the Three Forks is probably better than the Sanish as well. The economics of the lower benches are murky, but the geology says it could be better than the first bench. This will take some de-risking, but we should have a better idea by 2014.

In summary, QEP invested a large sum in Grail, Croff and Blue Buttes fields. In all honesty, I thought initially that QEP paid too much. The activity of other operators in the area shows I was wrong. The combination of these two formations could prove to be huge in upcoming pads. The revenues from these pads come on line quickly in a short period of time. The same could be said for costs. This could cause revenues and earnings to move around a lot from quarter to quarter. Much of this year's costs will fall in the first half of the year, with the bulk of profits realized in the second half. As for QEP's recent well announcements in both northeast McKenzie County and on Fort Berthold, it will take time to know how well they have done. IP rates are less credible in the short term and even using 90-Day IP rates can be misleading. I am not saying its South Antelope completions will under perform, but it is important to see how these wells deplete. Some operators use longer stages, or smaller amounts of proppant and water. These design's tend to cause production to drop significantly 6 to 12 months after completion. As for the short term, QEP is a name to own, but I would wait for a pullback.

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. 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.

Additional disclosure: This is not a buy recommendation. The projections or other information regarding the likelihood of various investment outcomes are hypothetical in nature, are not guaranteed for accuracy or completeness, do not reflect actual investment results, do not take in consideration commissions, margin interest and other costs, and are not guarantees of future results. All investments involve risk, losses may exceed the principal invested, and the past performance of a security, industry, sector, market or financial product does not guarantee future results or returns. For more articles like this check out my website at Fracwater Solutions L.L.C. engages in industrial water solutions for oil and gas companies in North Dakota. This includes constructing water depots, pipelines and disposal wells. It also provides contracting services for all types of construction at well sites. Other services include soil remediation. Please contact me via email if you are interested in working with us. More of my articles and other pertinent information on the oil and gas sector, go to