Over the past five years, the Denver-Julesburg (D-J) Basin has transformed from an industry afterthought into one of the most successful and active plays in North America. Rig counts have risen from near zero in 2009 to 53 horizontal rigs operating today. Operators have transitioned from drilling up to 32 vertical wells per section to planning for up to 32 horizontal wells per section. And drilling and completion investments have skyrocketed beyond $100 million per section in some areas, with acreage costs rising dramatically alongside.

The Jake 2-01H horizontal Niobrara well in late 2009 sparked a land rush throughout the Front Range area of the D-J Basin. Operated by EOG Resources Inc., the well made headlines with an initial production rate of nearly 1,000 boe/d and cumulative production of more than 70 Mboe in six months at a reasonable cost of about $4 million.

As word of the profitable well spread, land with similar geologic characteristics was leased from north of Cheyenne, Wyo., to south of Colorado Springs, Colo., a distance of more than 200 miles and covering an area of more than 5 million acres. In the first 12 months following the discovery well, leasehold prices quickly climbed from less than $100 per acre to $3,000-plus per acre.

As delineation of the vast swath of newly leased acreage proceeded in 2010 and 2011, winners and losers in the acreage rush emerged. Highly productive horizontal Niobrara wells were drilled around the edges of Wattenberg Field, south of Silo Field in southeastern Wyoming, around the Jake discovery well, and along the Colorado Mineral Belt that stretches northeast of Wattenberg Field.

Unsuccessful wells were drilled north of Silo Field, in northern Weld County, Colo., and east of Colorado Springs.

The accompanying table shows permit activity by year for six counties and demonstrates how permit activity has grown in some areas and disappeared in others. Consequently, several million acres of leases became nearly worthless, while another couple of million acres continued to increase in value. As competition in the basin accelerated for quality acreage, prices reached $6,500 per acre in early 2012 with the leasing of the state-owned, 21,000-acre Lowry Range to ConocoPhillips.

During this early delineation of the Niobrara, companies experimented with well spacing and testing multiple benches within the Niobrara and Codell formations. The original discovery area developed by EOG was generally drilled on 640-acre spacing with a handful of 320-acre tests. Anadarko Petroleum Corp., Noble Energy and others began testing 160- and 80-acre spacing in multiple zones along with horizontal redevelopment among 20-acre-spaced historical vertical production.

In 2013 and 2014 there were further announcements of downspacing success in multiple benches, with many companies planning for between 16 and 24 wells per section in some areas of the play. Recently, Whiting Petroleum and Noble Energy began drilling on patterns testing 32 wells per section.

As downspacing tests in the stacked pay intervals of the Niobrara and Codell were met with success, the average cost of acreage burden per development well dropped, with corresponding increases in acreage transaction values. In late 2012, the $10,000 per-acre mark was surpassed by Bonanza Creek for an undeveloped 5,638-acre, state-owned parcel on the edge of Wattenberg Field. Acquisitions by Bill Barrett, Bonanza Creek, Extraction Oil & Gas and others continue to demonstrate the immense potential seen in the play, with one recent transaction surpassing $40,000 per acre.

Acreage acquisition costs as a per-well burden have stayed relatively flat at about $1 million per well in recent transactions as drilling density increases and acquisition costs are spread over a greater number of wells.

Operational efficiencies and currently high rates of return may allow the acreage-cost-per-well burden to grow further. Continued successes in testing additional zones or additional downspacing would further enhance economics, but tests have slowed as companies tested the most prospective zones first and ultimate recovery factors pushed higher.

A number of factors will fuel further consolidation within the D-J Basin. The regulatory risks associated with development along Colorado’s Front Range initially tempered outside interest in entering the basin, but these concerns dissipated as damaging ballot initiatives were struck down late in 2014. Also, smaller players are finding it increasingly difficult to keep up with the immense investments required to develop through the drillbit and will pursue sales or partnerships.

Fortunately for those already in the basin, if the recent downturn in oil and gas pricing persists, the vast majority of current development is focused on highly economic areas with breakeven costs as low as $40/bbl of oil.

—Matt Meagher, Meagher Energy Advisors, mmeagher@meagheradvisors.com, 303-721-6354

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