The ostensibly stratospheric valuation implied by QEP Resources' (QEP) South Antelope acquisition in the Williston Basin (announced last Thursday) caught investors' attention. While specific estimates vary from analyst to analyst, the consensus seems to be that the transaction represents one of the highest prices paid per acre in the area. In my analysis, the acquisition implies a purchase price of over $40,000 per undeveloped acre which is record setting for the play. While shockingly high at the first glance, a closer examination shows that the price may be economically justified.
In the transaction, QEP agreed to pay $1.38 billion for 27,600 net acres in a highly productive over-pressured area of the play straddling Williams and McKenzie counties of North Dakota. The purchase includes proved developed reserves associated with 73 gross wells currently flowing at 10,500 Boe/d net rate, operating infrastructure including salt water disposal, and 146 identified net undeveloped drilling locations (mostly long-lateral wells, with 4 wells per 1,280-acre unit in each the Bakken and Three Forks/Sanish intervals).
Fine-tuning my transaction model based on additional data points from the conference call, press releases by the sellers and a more detailed analysis of the producing wells, I arrive at a valuation range of $425-$525 million for the acquired developed reserves. The lower end of the estimated range reflects PV-12% value at $90 WTI for producing wells and assumed 12-month weighted average time on production for the 32 high-EUR wells drilled after 1/1/2010 (shown on slides 4 and 5 of QEP's presentation with colored circles). The higher end of the range corresponds to PV-10% value at $90 WTI and 9 months assumed weighted average on-production life, respectively. The valuation also includes estimates for wells-in-progress and operating infrastructure. In my calculations, I assume average working interest of 54% for the 72 sections within and immediately adjacent to the operated block. For the 20 non-contiguous non-operated sections, I assume average working interest of 22%. The analysis required a variety of assumptions as QEP has provided a limited set of data, and no reserve figures (will only be available at year end).
The $855-$955 million balance of the total purchase price is attributable to the identified 146 net drilling locations. This translates in average value per location in the $5.9-$6.5 million range and effective price of over $40,000 per undeveloped acre. The very high per acre metric is attributable to the fact that two highly productive intervals are present across the entire property. The price may also reflect additional potential upside from higher well density, particularly in the Bakken, and possible development potential in the deeper Three Forks benches.
The value can be further allocated between the two intervals, the Bakken and TFS, based on equalized expected returns. I arrive at estimated $7.5 million paid for each middle Bakken location and $4.7 million paid for each Three Forks location (I assume the 146 net locations identified by the company are comprised of approximately 80 net Bakken locations and 66 net Three Forks locations). In my analysis, I use the reported EUR averages of 1,160 MBoe for the Bakken zone and 990 MBoe for the TFS zone as an estimate for future EURs. The relative valuation of the locations in the two zones highlights the dramatic impact that expected productivity of the acreage can have on its value.
QEP's acquisition highlights the extreme competitiveness and value transparency of the Williston M&A environment. In its many parts, the play is thoroughly modeled geologically and well delineated, giving both buyers and sellers a reasonable degree of confidence in the development economics. As a result, in the absence of a substantial post-acquisition improvement in oil recovery rate or drilling success within additional producing intervals (i.e., TFS deeper benches), it would be unreasonable to expect that an acquirer can capture much upside using the M&A venue for growth. In this specific case, the competitive auction resulted in, arguably, modest expected return to the buyer, in the 20%-25% range according to my model (based on a flat $90 WTI and $11 million D&C cost, before taxes and overheads). Given the execution and commodity price risks, this appears to be the minimum acceptable return from the buyer's perspective.
QEP has indicated that it intends to ramp up its drilling effort on the acquired property to five rigs by the end of the year (and possibly higher thereafter). Assuming the productivity of 10-12 wells per rig-year in the pad development mode, the operated block (the 72 sections with estimated approximately 240 gross drilling locations) can be fully developed in four and a half to five years. The upfront investment in the acreage creates a "carry" cost (which can be minimized with accelerated development). Using, for illustrative purposes, a 15% per annum "carry" rate, the average cost per acquired drilling location effectively increases to $8.2-$9.2 million. QEP's current drilling & completion cost per well in their existing Fort Berthold development is $11 million. For their completions, QEP has used the less expensive resin coated sand proppant. In the event the company's engineers are compelled to use ceramic proppant for the over-pressured wells on the newly acquired property (as the selling operator Helis Oil & Gas has done), the D&C cost would increase by another $1.0-$1.5 million. Add the $8.2-$9.2 million drillsite acquisition cost, as discussed above, and the estimated $0.5 million well tie-in expenditure, and the all-in cost per well can reach $21-$22 million.
What was driving QEP's decision to pay such a high price for the acreage? Most likely, the unique geology of the location and QEP's possible belief that EURs well above the reported 1.0-1.1 MMBoe can be achieved as the development progresses. However, the improved results can by no means be taken for granted.
The selling group in this transaction, which includes Helis Oil & Gas (the operator, private), Black Hills Corporation (BKH), Unit Corporation (UNT), and Sundance Energy (OTCPK:SDCJF) are receiving, arguably, close to the highest possible price that one can rationally expect given the operating risk involved. Unit will be using the $268 million proceeds from this and another smaller divestiture to strengthen its balance sheet in the aftermath of its recent $617 million Anadarko Basin acquisition from Noble Energy. Black Hills, a diversified electric generation and E&P company, will be using the $243 million proceeds to fund its capital program, including its $237 million Cheyenne Prairie Generating Station, without issuing equity. And Sundance Energy will redirect the $172 million in proceeds from the sale of its net 3,900 acres towards its other E&P projects with higher working interests/operatorship.
While very strong well results in the McKenzie and Williams counties is no news to the market, the transaction does highlights the acreage value along the north-to-south over-pressured corridor. Kodiak's (KOG) acreage in its Polar, Koala and Smokey operating areas seems to have a reasonable geologic similarity to the S. Antelope area and provides perhaps the most concentrated "read-through" on the per share basis. Among micro-caps, Triangle Petroleum (TPLM) seems to have relevant mineral interests in the area that may warrant a closer examination. Among larger-cap stocks, Newfield Exploration (NFX), EOG Resources (EOG) and several others have significant acreage in the proximity of the S. Antelope, although per share exposures are substantially smaller.
Disclaimer: This article is not an investment recommendation and does not provide a view on the value or price direction of any security.