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Recent questions about Northern Oil & Gas (NYSEMKT:NOG) have caused a pullback in shares. These questions (part 1 and part 2) followed a Barron's article about insider selling. The bears timed this well as Northern had outrun valuation in the short term, and was due for a pullback. Street Sweeper and Bronte Capital stated they were short the stock. It seemed the Street Sweeper articles focused on colorful language, with little focus on economics .

One question I found troublesome addressed depletion. Depletion, much like depreciation, allows the oil company to account for the reduction of a commodity's reserves. There are two types of calculations for depletion. The first is percentage depletion, calculated by a set percentage multiplied by the gross income from the property. The second is cost depletion, which looks at the total amount of resource to be extracted, how much was extracted during the tax year, and the total amount of money used to extract it. Depending on well type, all three variables can vary significantly. A conventional well differs from a horizontal well. Long laterals vary from short. Well types differ in cost, EURs and amount of resource extracted for the year. It is easy to see why the question about depletion is difficult to answer, which may be the reason for its inclusion in the articles.

Northern Oil & Gas derives 100% of its business in the Williston Basin. More specifically, they target the Middle Bakken and Three Forks shales. Three Middle Bakken / Three Forks focused companies were a close match:

  1. Brigham (BEXP)
  2. Oasis (NYSE:OAS)
  3. Kodiak (NYSE:KOG)

Brigham's well costs have been increasing, but returns are continuing to set the bar in the Bakken. Brigham has 371200 net acres. An EUR of 700 Mboe, well costs of $8.9 million, and NYMEX of 5-2-11 will produce an NPV-10 of $15.9 million and undiscounted payout of one year.

  • $8.9 Million in well costs
  • Estimated EUR 500-700 Mboe
  • 59 North Dakota Bakken / Three Forks wells with average IP of 2863 Boepd
  • North Dakota average 7-day IP of 1799 Boepd
  • North Dakota average 30-day IP of 1111 Boepd
  • North Dakota average 60-day IP of 837 Boepd
  • In the 4Q of 2010, 4 wells completed had an IP of 3591 Boepd
  • EUR of 700 Mboe has an economic life 34.8 years, undisc. payout is 1 year
  • 4Q 2010 IP average of 3591 Boed
  • 12/31/10 DD&A expense of approximately $20.47 Boe

Kodiak has quality acres east of Nesson. Its total net acres are 70000 in the Williston Basin. A Bakken long lateral with and EUR of 850 Mbo, well costs of $8.8 million, and $95 WTI will produce an NPV-10 of $17.3 million and payout in 17 months.

  • $8.5 to $9 Million in well costs
  • Estimated EUR of 750-850 Mboe east of Nesson
  • Estimated EUR of 500-700 Mboe west of Nesson
  • In the 4Q of 2010, 2 wells completed had an average IP of 1621 Boepd
  • Long lateral 30-day IP of 1170 Boepd
  • Long lateral 60-day IP of 1073 Boepd
  • Long lateral 90-day IP of 972 Boepd
  • Long lateral 180-day IP of 689 Boepd
  • 12/31/10 DD&A expense of approximately $18 Boe

Oasis has 303231 net acres in the Bakken / Three Forks trend. The majority of its leaseholds are in West Williston and East Nesson.

  • $7.5 million in well costs
  • West Williston gross reserves of 450-787 MBoe
  • East Nesson gross reserves of 393-675 MBoe
  • West Williston 7-day IP average of 536-915 Boepd
  • West Williston 60-day IP average of 415-708 Boepd
  • East Nesson 7-day IP average of 512-790 Boepd
  • East Nesson 60-day IP average of 386-611 Boepd
  • In the 3Q of 2010, 11 wells completed had an average IP of 1703 Boepd
  • 12/31/10 DD&A expense of approximately $19.91 Boe

Brigham, Oasis, Kodiak and Northern all have acreage located in the "Bakken Kitchen". Continental Resources (NYSE:CLR) coined this term, which is a continuous overpressured oil cell at its (Bakken shale) center. The Bakken Kitchen is located in the United States and does not progress north of the Canadian border. This is why Canadian Bakken well economics are not the same as in North Dakota or Montana.

Due to this, the comparison of Northern Oil & Gas and Petrobakken (PBKEF.PK) is difficult at best. Petrobakken's Q4 of 2010 production from Saskatchewan was 75% of the total. Production mix was 84% liquids and 16% gas. Northern Oil & Gas is 94% oil. Its 2011 capital forecast will be spent on 55 horizontal bilateral wells of the total 105 SE Saskatchewan wells. The remaining 50 wells are a combination of conventional wells and EOR projects. Of the $800 million in capital spent in 2011, only $225 million will be spent on SE Saskatchewan. Petrobakken bilateral well economics are:

  • $2.58 million in well costs
  • Estimated EUR of 190 Mboe
  • Average IP is approximately 250-300 Bopd
  • Payout in 1.1 years ($75 oil and $4.25 gas pricing)

Petrobakken states much of its double digit increase in DD&A expense comes from the TriStar acquisition. Increase in DD&A can also be linked to the economics of drilling 2 single wells versus the current 1 bilateral well. Initial horizontal well techniques using 2 singles produced:

  • $3.96 million in total capital
  • 1.7 year payout
  • Recovered 35000 less reserves recovered over the life of well vs. Bilateral

The recent switch to 1 bilateral well has made this company's horizontal wells much more profitable. As for depletion, it should not seem strange that depletion rates would be higher in SE Saskatchewan, as North Dakota Bakken wells-- in some of these estimates-- will payback the initial approximate $9 million in one year. This leaves (by Brigham Estimates) 33.8 years of possible resource production on a 700 MBoe EUR. Northern Oil and Gas has another advantage, as its non-operator model decreases well costs. Its current cost per net well is $6.3 million. This compares to Brigham and Kodiak's costs of approximately $9 million and $7.5 million by Oasis (more sand versus proppant has decreased costs).

Northern had a difficult first quarter of 2011. Even without the mark to market losses on oil hedges, it would have missed by 9 cents/share. Depletion was up 3 cents per barrel of oil equivalent from the fourth quarter. Most importantly, it reaffirmed 2011 guidance and is continuing to add acreage at reasonable price per acre. I would be more concerned about the quarter if it wasn't such a difficult winter, plus it seemed ahead of valuation in the short term. If Northern can get 50% of its acreage held by production or under the bit, I would expect a significant increase in market cap over the rest of 2011.

Disclosure: I am long BEXP, NOG.

Source: Depletion Is Not a Problem for Northern Oil & Gas, Mark to Market Oil Hedges Are