Past articles in this series show where the Bakken is headed in 2013 and beyond. Operators have done a great job, as they have developed pad drilling, zipper fracs, and pressure pumping techniques that not only have improved EURs, but also reduced costs. Companies have turned ideas into reality, and this is only the beginning. Operators are getting more proficient, as the first quarter was spent drilling and not completing wells. This is building an inventory, and now that the weather is nice we should see a large number of pad completions turned to sales in the third quarter. Most operators are using two mile thirty stage laterals with large amounts of sand and ceramic tails. Better results are being seen from companies using more water and proppant. As the source rock is better stimulated, it will take more of both to fill in the fractures and keep crude flowing to the well bore. In my last article, I covered EOG Resources (EOG). Its comment about Bakken rate of return could prove to be a turning point for this play. EOG is seeing returns in its Bakken wells that rival the Eagle Ford. These are triple digit returns, and more importantly show us that EOG's technologies and not geography are the reason for its outperformance.
Continental (CLR) has shown vast improvements over the past year. Well design improvements are increasing production, and decreasing costs. It averaged 121500 Boe/d in the first quarter of 2013. Bakken net production was up 60% year over year and 14% quarter over quarter. It has 22 operated rigs in the Bakken which is 12% of the entire industry. It is the number one leaseholder in the Bakken with 1.2 million net acres. It completed 66 Bakken/Three Forks wells in the first quarter. Its pad development already shows an improvement in cycle time of 36%. Comparing a six well pad to six single wells, Continental saved $7.5 million and 73 days. This Florida-Alpha project had costs under $8 million/well. IP rates averaged approximately 1600 Boe/d. This is just the beginning, as we are still very early. Continental also had some good results from the second bench of the Three Forks. The Barney 2-29H-2 had an IP rate of 1100 Boe/d and Stedman 2-24H-2 produced 1030 Boe/d. Both wells were in Williams County. This shows the second bench is still quite good even 15 to 20 miles north of the Charlotte well. Stedman 3-24H-3 was a test of the third bench that IP'd at 465 Boe/d. It is important to note that the Stedman wells were located in western Williams County very close to the Montana border. The first test of the third bench was at Charlotte, and it had an IP rate of 953 Boe/d. The play is not as deep here, and lower pressured. This would account for the low IP rate. More importantly, the third bench is completely independent of the second. Continental is currently de-risking the lower benches of the Three Forks in 2013. Tests will be in Dunn, Divide, McKenzie, and Williams counties. Continental has 4 density pilot projects planned for 2013. These are very significant as it not only tests several different source rock, but also the spacing between. It will be more interesting, when we see these density tests in the third bench. Well costs in April averaged $8.3 million. This includes both single and pad wells. This is a large improvement from the $9.2 million in October of last year. Oil differentials were $4.29/bbl in the first quarter. Continental estimates the full year average will be between $5 and $7/bbl. This tighter differential has a lot to do with crude being railed out of North Dakota. 80% of Continental's oil is transported via the railroad. It has taken advantage of getting oil to the east and west coast.
Whiting (WLL) saw production increase 4% over the fourth quarter of 2012. Hidden Bench production was up 27% over the previous quarter. 12 wells are already flowing back in the second quarter. 5 are in Hidden Bench, while the other seven are spread over the Pronghorn, Cassandra and Sanish. In the first quarter, Whiting had very good results in Montana. Missouri Breaks well results averaged IP rates of 1200 Boe/d. Good results were seen in the Sanish. Roggenbuck 21-25H had an IP rate of 2053 Boe/d. It has 704525 net acres in the Bakken. Whiting paid an average cost of $526/acre. Whiting separates it North Dakota/Montana acreage into three prospects. The first is the Sanish prospect which is made up of Sanish and Parshall Field acreage in Mountrail County. This is considered its core acreage. This area has some of the best middle Bakken wells in North Dakota. This area is prospective the middle Bakken and upper Three Forks. Whiting believes the Sanish can support up to three more wells per spacing unit in the middle Bakken D zone. The Western Williston Prospect is Whiting's northeast McKenzie, southeast Williams and eastern Richland county leasehold. This includes Tarpon, Cassandra, Hidden Bench, and Missouri Breaks. The middle Bakken is still considered very good in this area. Upside is linked to the Three Forks, as it has excellent thickness. In some areas of this prospect all four benches of the Three Forks are present. Whiting recently announced that it believes the upper Three Forks will support 3 wells per spacing unit in Missouri Breaks. Whiting plans to test the middle Bakken Silt in Hidden Bench. It is believed this will increase recoveries for the middle Bakken. In Cassandra and Tarpon it is believed the 2nd bench of the Three Forks is charged by the lower Bakken shale. This could increase total locations by three. Its Southern Williston prospect includes Pronghorn and Lewis & Clark. The middle Bakken thins significantly here. The play is prospective the Pronghorn Sands/Three Forks. Whiting believes this area can support up to six wells per spacing unit. Below I have listed its potential locations by prospect.
|Middle Bakken||Pronghorn Sands||Three Forks 1||Three Forks 2|
The table above shows the number of locations Whiting is planning to use in developing its prospects. Keep in mind that we could see these numbers increase. An example would be Hidden Bench. This prospect has a very large number of middle Bakken and upper Three Forks locations per spacing unit. This area is prospective the second bench, but it will take time to develop this source rock in this specific area. There is a good chance the Pronghorn will also have second bench upside as well. Big Island is prospective the Red River formation. This area has been developed as a vertical play. In July it plans its first horizontal well. The economics of this play are very interesting, as it is very deep and the source rock is very thick. Depending on how this works, we could see more Red River locations in Montana by other operators. Whiting has been getting better production from its horizontals. Its synergistic frac design better stimulates the source rock. Since there are more/better fractures it is able to use more water and proppant. It has also been testing sliding sleeves vs. plug and perf as well. Whiting believes the lower pressured areas benefit little from the use of sliding sleeves, but in deeper areas it produces better results.
Magnum Hunter (MHR) has been a busy company of late. It sold Eagle Ford assets to Penn Virginia (PVA). Magnum Dismissed its auditor PricewaterhouseCoopers after questions arose about financial statements. Now that attorneys are smelling blood there will be all sorts of issues propping up with respect to litigation. I liked the sale of its Eagle Ford leasehold, as the company was too levered for my comfort (which is a reason I don't own or trade the stock). Expect large swings in the stock's value going forward.
In January, Magnum spud its first operated middle Bakken well in Divide County. Until now, this has been a play on the Three Forks. This is not top notch acreage, but it has 180000 net acres in the Williston Basin. 130000 net acres are in North Dakota with 90000 of those acres in Divide. This acreage is surrounded by Continental , Baytex (BTE) and Samson. Third-party midstream should be online this month to process natural gas and NGLs. Magnum's well design has continued to improve. It has continually added stages, water and proppant. Well costs average $7.1 million. Differentials have decrease to $4/bbl to WTI. Magnum's EUR range is 730 MBo to 550 MBo. At today's oil prices, these wells have IRRs of 39% to 56%.
Abraxas (AXAS) spends 68% of its budget on the Bakken. It reported a difficult winter in North Dakota's first quarter. It placed two wells on production. The average 30-Day IP rate is 524 Boe/d. These wells had mechanical issues for which Abraxas received compensation from the third party service provider. EURs for these two wells are modeled at 475 MBoe. Its 4-well Lillibridge East pad consists of two middle Bakken and two upper Three Forks. Pad wells have an average cost of $8.5 million. This is important as it had spent as much as $13 million on a previous well. It has adopted a 10000 foot 28 stage frac. This is a big improvement over previous designs. It has one rig working the Bakken. Its Northfork acreage is near leaseholds of Exxon (XOM), SM Energy (SM) and ConocoPhillips (COP). Its results have not been as good as IP rates of Exxon and SM were around 1000 barrels of oil per day. Conoco's were 2000+ barrels of oil per day.
Emerald Oil (EOX) recently completed its first operated Bakken well. It had a 30-Day IP rate of 1025 Boe/d. Its operated program is going well and plans to soon drill its 6th. It now can complete drilling in under 30 days vs. the 30 to 40 days estimated initially. Well costs have decreased by $1 million to $10 million. Operating efficiencies has allowed Emerald to increase the total number of wells drilled in 2013. 11 wells will be completed this year vs. the old estimate of 10. Emerald added 6000 net acres in McKenzie County. It has approximately 54000 total net acres in the Bakken. 44% of this is operated. Its McKenzie County operated acreage is in the same general area as Triangle (TPLM). Hess (HES) and Exxon also have completions nearby. 30-Day IP rate comparisons range from 40 Boe/d to 912 Boe/d. Emerald's Pirate 1-11-2H was much better at 1025 Boe/d. It estimates EURs of 500 MBoe to 750 MBoe. Emerald estimates a payback of 1.4 to 2.4 years. If we use $100/bbl of oil a 750 MBoe well would payback in one year. In the first quarter average production was 1065 Boe/d from non-operated leasehold. For the full year, Emerald estimates this will increase to 1680 Boe/d. It plans to exit 2013 at 2600 Boe/d. Average crude selling price was $89.71 in the first quarter. Bakken/WTI differential was $4.57/barrel.
In summary, conditions are improving in the Bakken. Better well designs are producing more resource, while well costs are decreasing. Operators are using more stages, and larger amounts of proppant and water. Costs have decreased so much that well costs are lower even with a more complex design. Operators are more proficient decreasing drilling times. Pad wells decrease completion times through zipper fracs. Although WTI pricing is lower now than a year ago, Bakken/WTI differentials have tightened and margins have improved. I expect these differentials will remain tight through year end as crude is railed to the east and west coast refineries. The number of locations continues to increase as density pilots provide for tighter well spacing. Additional locations are added in deeper benches of the Three Forks as well. Geology like the Bakken silt are being used to add locations also. Deeper formations like the Red River may provide more horizontals in areas where the middle Bakken and Three Fork's benches are not as good. Bakken economics are setting up for a good 2013. Operators will have a large number of pad wells turned to sales after midyear. This should be further supported by lower well costs. Due to the large increase in production, smaller operators could see a rapid increase in share price in the latter half of this year.