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This continues the analysis of potential implications of QEP Resources' (QEP) South Antelope acquisition in the Williston Basin for Kodiak Oil & Gas (KOG) acreage portfolio. This section discusses Kodiak's key operating areas. The summary of the results and key conclusions are presented in Part I.

Acreage Portfolio

Kodiak's Williston Basin portfolio includes five primary operating areas: the Fort Berthold Indian Reservation leases (Dunn County), the Koala (McKenzie County), the Polar (Williams County), the Smokey (McKenzie County), the Grizzly (McKenzie County), and the Wildrose (Williams and Divide counties).

(click to enlarge)
(Source: Kodiak Oil & Gas August 2012 Presentation)

Koala, Polar and Smokey Operating Areas

Kodiak's Koala (10,000 net acres), Polar (42,000 net acres) and Smokey (17,000 net acres) leaseholds appear comparable to the South Antelope properties (27,600 net acres) being acquired by QEP. Like the South Antelope, the three areas are located within an over-pressured north-to-south corridor along Nesson Anticline, are characterized by very strong well results and high operatorship, and are to a large degree "blocked up." For reference, Kodiak paid approximately $1 billion over the past 12 months to acquire the properties and has drilled mostly very successful wells since assuming the operatorship (results are summarized on pages 24 and 25 of the company's August presentation). As I mentioned in Part I of this article, one of the differences with the South Antelope block is the lack of sufficient delineation in the Three Forks interval, which leaves an uncertainty with regard to TFS EUR range. In addition, the Polar and Smokey areas will require more wells and production histories in the middle Bakken to be fully delineated (Kodiak has drilled only a few operated wells since it acquired the properties).

Notwithstanding the insufficient delineation, the very impressive wells that Kodiak has reported in all the three areas, including the Three Forks results, indicate that the acreage may be highly productive in both the middle Bakken and Three Forks. I do not rule out that a significant part of the Koala, Polar and Smokey acreage may come close in quality (and valuation, once the delineation work is complete) to the South Antelope block. Timing-wise, the HBP requirements should be met in the Koala and Smokey areas this year and in the Polar in 2013, whereas the Three Forks assessment program is unlikely to be complete until 2014.

I assume the following EURs and valuations to the undeveloped acreage (based on flat $90 WTI, $11 million D&C and tie-in cost per well, and 20% required rate of return assuming accelerated development; excludes locations already drilled):

  • 69,000 net acres prospective for the middle Bakken yielding approximately 180-190 undrilled locations on 320-acre spacing. Assumes 1.0-1.1 MMBoe average EUR per well (this compares to 1.16 MMboe for the South Antelope) with 87% crude oil yield (based on the analysis of the well data provided by Kodiak, pages 24-25 of the August 2012 presentation). $6.0 million - $7.5 million estimated value per location. Total potential value: $1,080 million - $1,425 million.
  • 69,000 net acres prospective for the Three Forks yielding approximately 150-200 undrilled locations (on 425-acre to 320-acre spacing, respectively). Assumes 600-900 MBoe average EUR per well with 87% crude oil yield. $1.5 million - $4.7 million estimated value per location. The lower end of the estimate reflects the "option value" on future reduced well costs, improving well completion techniques, and higher oil prices. Total potential value: $225 million - $900 million.

Total estimated potential value of the Koala, Polar and Smokey operating areas: $1,305 million - 2,325 million. I emphasize that the valuation represents potential value of acreage which needs to be validated, particularly in the Three Forks zone, by additional delineation.

Dunn County Operating Area

Geologically, Kodiak's Dunn County acreage (34,000 net acres) is part of the highly productive trend stretching from the Parshall field north of the Fort Berthold Indian Reservation all the way down towards the Bailey field, which is immediately to the south of the Reservation. Kodiak's leases are located in the over-pressured portion of the trend which is close to the Eastern Expulsion edge (the company's acreage position is well illustrated by the map from QEP's presentation: the western portion of Kodiak's acreage is encircled from the north, east and south by QEP leases which are shown on the map below in yellow).

(click to enlarge)
(Source: QEP Resources November 2011 Presentation)

The leasehold's more productive northwestern part (map below) is well delineated, mostly in the Bakken interval. The southeastern block is less delineated; it is located closer to the up-dip Expulsion edge and as a result its eastern half may prove to be sub-economic (as the formations move up dip, the reservoir quality deteriorates, and so do well performance and EURs). The Dunn County leasehold should be HBP by year end.

(click to enlarge)
(Source: Kodiak's August 2012 Presentation)

KOG has drilled some very impressive wells in Dunn County (page 23 of the August 2012 presentation) and estimates long lateral Bakken EURs in the 800-900+ MBoe range on average (page 10 of the presentation). Kodiak's EUR estimate is confirmed by the type curve used by Enerplus (ERF) whose Fort Berthold acreage is immediately to the west from Kodiak's: EFR uses 905 Boe EUR comprised of 800 Mbbls of oil, 50 Mbbls of NGLs, and 300 MMcf of gas; 30-day IP of 1,240 Mboe/d; and drilling, completion and tie-in cost per well of $12 million for 9,500 ft lateral with 24 frac stages. At the same time, Kodiak's estimated EUR is substantially higher than the 500-600 MBoe that QEP sees across its Fort Berthold acreage. The difference may be reconciled by the fact that QEP's leases are mostly to the east of Kodiak's block, i.e. further up dip and therefore less productive on average.

In the Three Forks interval, Kodiak has drilled fewer wells, although the results have been very positive. Of the six TFS wells, three wells were exceptionally strong, matching the best wells in the Bakken zone. Further to the east, the CE 15-22-15-3H3 test, which was drilled to delineate the eastern productivity edge of the Three Forks interval, averaged 451 Boe/d over a 90-day period. While the result implies a sub-500 MBoe well, it should be viewed as a success, given the well's frontier location.

For the purposes of my analysis, I use the following assumptions for KOG's Dunn County acreage. Given that the economics of the less delineated southeastern portion of the acreage remain in question, I exclude approximately 6,000 net (10,000 gross) acres from the total of 34,000 net acres (additional delineation may resolve the uncertainty). Further, I take into account the possibility that the two reservoirs, the Bakken and TFS, are not evenly distributed across the acreage. Generally, in this part of the trend, as one moves eastward towards the expulsion edge, the land becomes unprospective for the Three Forks earlier than for the Bakken. I therefore "risk" the TFS acreage by assuming greater productivity on the western 50% of the acreage and lower productivity on the eastern 50% of the acreage.

I assume the following EURs and valuations to the undeveloped acreage (based on flat $90 WTI, $11 million D&C and tie-in cost per well, and 20% required rate of return assuming accelerated development; excludes locations already drilled):

  • 28,000 net acres prospective for the middle Bakken yielding approximately 70 undrilled locations on 320-acre spacing. 800-900 MBoe EUR per well based on Kodiak's estimate. $3.3 million - $4.7 million estimated value per location. Total value: $230 million - $330 million.
  • 14,000 net acres prospective for TFS yielding approximately 30-40 undrilled locations on 425-320 acre spacing. Assumes 680-765 MBoe EUR per well (approximately 15% less than the middle Bakken). $2.0 million - $2.9 million estimated value per location. Total value: $60 million - $115 million.
  • 14,000 net TSF acres yielding 30 undrilled locations on 425-acre spacing. Assumes 500 MBoe EUR per well. While these drilling locations do not meet the 20% minimum return requirement, they are economic using a lower threshold. $0.5 million - $1.0 million estimated value per location reflects the "option value" on future reduced well costs, improving well completion techniques, and higher oil prices. The value is negatively impacted by the likely development delay as these locations would not be among the first to be drilled. Total value: $15 million - 30 million.

Total estimated potential value of Dunn County undeveloped acreage: $305 million - 475 million. I emphasize that the valuation reflects potential value of the TFS interval and will need to be validated by additional delineation drilling in the interval (may be accomplished by the end of 2013 assuming one operated rig).

Grizzly and Wildrose Operating Areas

For the time being, I assign a $1,000-$2,000 per acre value range to the Grizzly acreage and no value for the Wildrose acreage. Kodiak's initial wells in both areas have shown sub-economic production rates. The Grizzly acreage holds some promise as it appears on-trend with the productive areas nearby. However, the economic productivity must be confirmed by better well results. The timing of the assessment drilling is uncertain as Kodiak has its hands full with more productive leases. The Wildrose is much more of an exploration block. While it is too early to condemn the acreage, there is no ground to assign much value to these properties.

Total Grizzly and Wildrose undeveloped acreage value: $25 million - $50 million.

Undeveloped Acreage Summary

Adding across Kodiak's properties, I derive:

Total estimated potential value of Kodiak's undeveloped acreage: $1,635 million - $2,850 million.

Observations

The value of undeveloped acreage shows strong non-linear dependence on expected EUR (i.e., a 30% increase in expected well productivity from one property to another may translate in doubling of per-acre values - figures being purely illustrative). Such relationship is primarily the result of operating leverage and cash flow compounding. However, there is another important contributing factor. The best acreage is almost certain to attract maximum capital allocations and be developed quickly, bringing forward cash flows and increasing returns. By the same token, development of marginal acreage will likely be deferred until technological advancements translate into higher well productivity. These factors explain the very significant premium that top quality acreage commands over fringe areas.

The QEP transaction highlights value within property portfolios of several companies who have acreage immediately adjacent or comparable to the South Antelope block. These include ConocoPhillips (COP), Hess (HES), Continental Resources (CLR), WPX Energy (WPX), EOG Resources (EOG), Enerplus, and Newfield Exploration (NFX). On the smaller cap side, Triangle Petroleum (TPLM) has significant for its size acreage interests in the McKenzie and Williams counties.

Disclaimer: This article is not an investment recommendation and does not provide a view on the value or price direction of any security. Any analysis presented in this article is illustrative in nature, is based on an incomplete set of information and has limitations to its accuracy, and is not meant to be relied upon for investment decisions. Please consult a qualified investment advisor.

Source: Kodiak Oil & Gas: 'Read-Through' From QEP Resources' South Antelope Acquisition - Part II