Continental Resources (CLR) is levered to the Williston Basin. With approximately one million acres in North Dakota and Montana, it offers exposure to virtually all areas of the Bakken/Three Forks. Going forward, Continental has upside on both the top and bottom lines. 2012 drilling and completion improvements have decreased costs and increased production. Proppant and water costs continue to decline allowing for increased usage per well. This is improving recoveries. Eco-Pad development is expanding at a fast rate. Oil transportation to the east and west coasts provide realized pricing equivalent to Brent.
The picture above shows middle Bakken thickness in North Dakota. It is a good representation of Continental's reasoning for its Bakken acquisitions. The darkest area represents its greatest thickness. The Nesson Anticline runs north to south next to this thick shale. It is the largest hydrocarbon productive structure in North Dakota and Continental's focus of development. Most of the vertical wells targeting the Madison group were located on and around the Nesson Anticline. This acreage has a deeper pay zone. Its gas to oil ratio, or GOR, is also higher. A higher GOR coupled with a deeper pay zone provides better IP rates. The GOR can be misleading, as higher rates include increased gas production. It is important to break production down as large IP rates and EURs do not always equate to better economics. EOG Resources has documented the difference in resource produced from its Mountrail and northeast McKenzie county fields.
The above table shows this difference. The change is significant as these areas are only 30 miles apart. On a barrel of oil equivalent basis, well economics change significantly. Natural gas is not the only reason, as natural gas liquids, or NGLs, have also declined in value year over year. For the third quarter of 2012, EOG Resources reported a year over year decrease in NGL realized prices of approximately $20/Bbl. This is a 40% decline. In response, EOG has pulled dollars from its combo plays to focus on crude. It could take years for infrastructure to meet NGL production. We should expect soft pricing in 2013. Using $80 oil, $30 NGLs and $3 natural gas prices, a Mountrail well will produce $9.42/Bbl more than a NE McKenzie County. A well modeled for an estimated ultimate recovery, or EUR, of 1000 MBoe, will produce $9.42 million more in revenue.
The above picture shows Continental's current acreage (yellow). Acreage held by production is shown in green. The initial Bakken land grab focused on Mountrail County. Whiting's (WLL) Sanish Field and EOG Resources' (EOG) Parshall Field are examples. Continental went a different direction following the Nesson Anticline from southeast Divide to northwest Dunn counties. The bulk of this acreage resides in northeastern McKenzie County. This is important, as interest in NE McKenzie has grown significantly over the past two years. QEP Resources' (QEP) acquisition of Helis's acreage in Croff and Grail fields proves this value. The best wells in this area targeted the upper Three Forks, with consistent EURs of 1000 MBoe. Wells have modeled to a maximum EUR of 1500 MBoe. This area is inconsistent with the rest of the basin, as the upper Three Forks outperforms the middle Bakken in this field. In the general vicinity of this field, the upper Three Forks has produced 10 wells with more than 1101-1500 Mboe. The middle Bakken has produced 8 within this range.
The above area in purple is the Helis acquisition. Valuations on this purchase per acre have varied significantly. Most would contend QEP paid too much, but some of the premium was paid for information on well design. QEP hopes this will benefit its Fort Berthold wells. It is rumored other operators, like Kodiak (KOG) were interested in the Helis acreage. This aided in increasing the selling price. Continental has a large number of acres to the north, northwest and southwest of this area. I would assume Continental wouldn't achieve these lofty results in its adjacent fields, but there is upside. The table below shows the Helis well design and results in Grail Field this year.
These results are a combination of geology and skill. These results are very good. 90-day IP rates are measured in barrels of oil per day. If gas and natural gas liquids are included, every well models for EURs over 1000 MBoe. Repeatability should be considered when evaluating Grail and surrounding fields. If Helis was able to produce these results, other operators should as well. Geology differs from one mile to the next. These changes must be considered to value this geology. I would guess this area is very good throughout, but Helis was getting more out of its acreage than the competition. Other fields in this area have provided excellent results (although not as good) for operators like Kodiak, Newfield (NFX) and Whiting.
Well costs continued to pull back in 2012. The Bakken has historically had higher costs, as infrastructure had to be built. Texas and Oklahoma are different as both have been top oil producers for a long time. The Bakken has additional issues linked to weather, a low population, and deep pay zones. Weather and distance from refineries will always be an issue, but in time the Bakken will share equal costs with other states. Continental reports overall well costs have decreased by 25% from the first to third quarter of 2012. A combination of developments have created this improvement. Completion times have decreased by 25%. This has helped to push down the cost per stage from $124,000 to $98,000. Proppant costs are 40% less. These costs have been hard to identify. Operators are taking these decreased costs and buying more sand for the same price. The same amount is spent, but this savings is seen through better IP rates. Increased availability of drilling and completion crews have decreased costs. Crews use less time pad drilling. 45% of Continental's rigs are currently on Eco-Pads. Look for this percentage to continue higher in 2013. It creates a savings of 10% when compared to non-pad drilling. Wells drilled per rig has increased 33%. The synergies created by Eco-Pads will continue as Continental gets more comfortable. Water costs are also decreasing. More disposal wells have been drilled, and more water wells are on line. Water is trucked shorter distances, and prices continue to decrease with competition. Fresh and produced water pipelines are now in place, decreasing trucking demand. There are a large number of trucks parked in North Dakota, and are easy to get on short notice. Salt water disposal and fresh water distribution systems provide a $4 savings per barrel of oil. Currently, single well costs are $9.2 million and Eco-Pads are $8.5 million. By the end of 2013, Continental estimates single well costs of $8.2 million with Eco-Pad wells falling to $7.5 million.
Differentials could provide significant upside to the Bakken in 2013. Estimates show improvement, but I believe bigger operators will benefit more. This optimism stems from rail not pipeline. Pipeline additions will help to improve transportation, but the rails offer more. EOG's third quarter is a good example as almost all of its Bakken crude is railed to St. James. It receives Light Louisiana Sweet or LLS pricing, which is a premium to West Texas Intermediate, or WTI. There may be a better venue in 2013. Alaskan North Slope or ANS pricing is used on the west coast. Its pricing is closer to that of Brent. This premium has little to do with quality and more to do with location. The west coast is effectively shut out from the cheap oil of the mid-continent. Pipelines do not extend to the west, as the Rocky Mountains provide an effective barrier. Tesoro (TSO) has a big presence on the west coast, and a mid-continent refinery in Mandan, North Dakota. This refinery has consistently been its best performer due to its exposure to cheap feed stock. Tesoro's Anacortes, Washington refinery is now receiving 30,000 barrels of Bakken crude per day. I would expect Tesoro and other west coast refiners are looking for ways to get mid-continent crude. It's more a question of how at this point.
Starting in the fourth quarter of this year, Continental has increased crude transports by rail. In November, it sent 65% of its crude this way. Continental understands pipeline capacity increases will not meet production in the short to moderate term. This improved Continental differentials. This decreased from $9.45/Bbl in the third quarter to $5.19/Bbl in November. If WTI differentials to Brent remain wide in the long term, producers will be motivated to figure out how to get oil to PADD 1 and PADD 5. Continental plans to rail oil to Puget Sound and California. It will get oil to the east coast and Canada via shipping.
In summary, Continental has upside in 2013. The number one variable is differentials. EOG has shown in the third quarter using other methods to transport crude outside the mid-continent are economic. Oil sent on the rails from the Permian, Eagle Ford and Bakken to St. James sold for $109/barrel. Oil piped to Cushing received $88/barrel. Bakken barrels sent to Clearbrook realized pricing of $84/barrel. Wide differentials more than substantiate added costs of transport. EOG's realized oil price in the third quarter was more than $5 higher than WTI. Continental's third quarter realized price was $9.45 below WTI. Remember, realized oil prices are directly seen on the bottom line. Well costs will continue lower. I would guess Continental has service contracts in the Bakken that have not expired. This should offer opportunities to sign deals at lower rates in 2013. Infrastructure is catching up with production, and next year will provide well cost decreases. Continental continues to see well design improvements. Production numbers will improve a great deal with increased water and proppant usage. With a large number of ways to improve its business, Continental seems well placed for 2013. Barring a collapse in the price of oil, it should continue to grow ahead of analyst estimates. In part two of this article, I will break down Continental's production improvements and its business in the SCOOP.
Additional disclosure: For the Helis Well 20780*, I used a later start for measuring the IP rate. This well had some initial production problems so I used the well restart time to properly measure.90-Day IP rates are measured in barrels of oil per day.Laterals are measured in feet.Water is measured in gallons.Proppant is measured in pounds.Boe/d: Barrels of oil equivalent per dayBo/d: Barrels of oil per dayEUR: Estimated ultimate recoveryIP Rate: Initial production rateThis is not a buy recommendation.