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Vol. 17, No. 21 Week of May 20, 2012
Providing coverage of Bakken oil and gas

The Bakken from five points of view

Magnum Hunter compares its Williston basin economics to Continental, Denbury, Kodiak and GeoResources

Eric Lidji

For Petroleum News Bakken

In April, Magnum Hunter Resources Corp. (NYSE: MHR) announced a $311 million deal to grab more working interest across its Bakken and Three Forks properties in the Williston basin.

Although small, Magnum Hunter operates in three of the most economic liquids-rich unconventional regions in North America: the wet-gas Appalachian basin, the oily Eagle Ford shale and the oily Williston basin in North Dakota, Montana and Saskatchewan.

With the goal of becoming a majority oil producer, Magnum Hunter is focusing on the latter two plays this year. The company plans to spend 92 percent of its upstream capital budget in the Williston and Eagle Ford, up from 67 percent during its last budget, and recently added $150 million to its current spending plan, for a total of $325 million.

Magnum Hunter holds some 125,000 net acres in the Williston basin, which wins out for capital this year, but trails the Eagle Ford in economics.

Magnum Hunter plans to spend $170 million drilling 80 gross (34 net) wells in the Williston compared to $130 million drilling 28 gross (14 net) wells in the Eagle Ford.

Magnum Hunter estimates a 43 percent internal rate of return, IRR, in the Williston.

Although that figure covers the entire basin, the company is making different assumptions across the play. For its North Dakota wells, Magnum Hunter estimates an average well cost of $6.9 million and an estimated ultimate recovery, EUR, rate of 350,000 barrels of oil equivalent, while in Saskatchewan it estimates an average well cost of $3.4 million and an estimated ultimate recovery rate of 185,000 barrels of oil equivalent.

The increased cost in North Dakota is largely the result of longer laterals.

By comparison, Magnum Hunter estimates a 54 percent internal rate of return, IRR, in the Eagle Ford based on an average well cost of $9 million and an EUR of 433,000 barrels of oil equivalent. In the liquids-rich Marcellus shale, Magnum Hunter estimates a 33 percent IRR based on an average well cost of $6.5 million and an EUR of 8.2 billion cubic feet of natural gas.

Those figures assume oil prices at $90 per barrel. When prices approach $105 per barrel, the plays become almost even, with IRRs increasing to around 60 percent in both sections of the Williston basin and to around 63 percent in the Eagle Ford, the company said.

Although the Eagle Ford currently beats the Williston within the Magnum Hunter portfolio, Magnum Hunter claims its Williston assets outperform its competition in the region. While its 43 percent IRR trails Kodiak Oil & Gas Corp. (44 percent) it beats Continental Resources Inc. (37 percent), Denbury Resources Inc. (27 percent) and GeoResources Inc. (25 percent), and its well costs are lower than all four companies.

Continental eyeing pads

How do those other companies see the matter?

Continental is a leading player in the Williston basin’s Bakken and Three Forks formations, both part of the Bakken hydrocarbon system

The Oklahoma City-based company produced 85,526 barrels of oil equivalent per day during the first quarter, up 66 percent year over year.

In the Bakken system, Continental holds nearly 1 million net acres in North Dakota and Montana and produced 48,024 barrels of oil equivalent in the first quarter, an 88 percent increase year over year.

Continental expects production across its entire portfolio to grow between 47 and 50 percent this year and to triple between 2009 and 2014, propelled largely by the Bakken.

With oil at $90 per barrel, Continental estimates around a 39 percent rate of return for single wells and around a 46 percent rate of return for pad drilling. Those rates increase to 52 percent and 62 percent respectively when oil hits $110 per barrel. The figures assume an average completed well cost of $8 million for single wells and $7.2 million for pad drilled wells with an EUR rate of 603,000 barrels of oil equivalent for both.

Those returns could improve as Continental becomes more efficient. The company plans to increase its pad drilling in the coming year and claims to have reduced its spud-to-spud cycle time by 30 percent over the past six months. Continental is still railing around half of its Bakken production to market, though, a significant cost increase over pipelines.

Continental also operates in the Woodford formation of Oklahoma and the Niobrara formation of Colorado, but plans to decrease activities in both plays this year.

Bakken versus EOR

Denbury focuses primarily on capturing carbon dioxide and injecting it into older oil fields to improve recovery rates, but with its arrival in the Bakken in recent years, the Texas-based independent is now a fast growing unconventional oil producer as well.

The two approaches involve different financial models. How do they stack up?

With oil prices at $90 per barrel, Denbury estimates a 27 percent IRR for its Bakken properties compared to 39 percent for its average enhanced oil recovery project in the Gulf Coast. The model assumed an average Bakken well cost of around $9.6 million and an estimated ultimate recovery of 575,000 barrels of oil equivalent.

While current oil prices above $100 per barrel could bump Bakken IRRs up to “low 30s,” according to CEO Phil Rykhoek, drilling costs are higher than originally anticipated. The Bakken wells Denbury drilled in the first quarter cost between $10.5 million and $11 million each. The company hopes to get that below $10 million soon through pad drilling.

Until recently, Denbury has been drilling single wells to hold acreage in the Bakken. While the company plans to use one rig this year to continue drilling single wells in the Three Forks, its remaining rigs will shift to pad drilling, a more cost effective approach.

Perhaps for that reason, Denbury said it is done acquiring property in the Bakken except for “little add-on pieces.” Going forward, “most of the expansion or acquisitions would likely be or almost certainly be (enhanced oil recovery) candidates,” Rykhoek said.

To manage increased costs in the Bakken, Denbury recently added $80 million to its capital budget for the play this year, bringing total spending plan to about $480 million.

Denbury is budgeting about $1.5 billion across its portfolio this year.

Denbury produced 15,114 barrels of oil equivalent per day in the Bakken during the first quarter, up 164 percent year over year and 29 percent quarter over quarter. It attributed the increase to improved completion activities and accommodating weather this winter.

Those encouraging results are making Denbury slow down its slow down in the Bakken.

While Denbury originally planned to cut its rig count to three from a 2011 peak of seven, the company is now planning to keep a fourth rig in the play. Why not more? The short answer, Rykhoek said, “is we’re just trying to manage our cash flow vis-à-vis debt.”

Denbury operates in the Gulf Coast and the Rocky Mountains, and is the largest producer in Mississippi and Montana. The company holds some 200,000 net acres in the Bakken.

Wide range for Kodiak

Kodiak reports a 44 percent IRR for its average well in the Bakken based on a $10.5 million well cost, but the rate rises and falls with prices and production.

The figure is roughly the midpoint of that range. For wells with an EUR rate of 650,000 barrels of oil, Kodiak estimates a 25 percent IRR when oil prices are $75 per barrel. For wells with an EUR rate of 850,000 barrels of oil, Kodiak estimates a 69 percent IRR when oil prices are $95 per barrel.

The high end is becoming a realistic assumption for Kodiak. In Dunn County, N.D., Kodiak is reporting EURs between 800,000 and 900,000 barrels from long lateral wells.

The Denver-based Kodiak currently holds around 157,000 net acres in the Bakken.

Although focused on the Williston basin of North Dakota and Montana, Kodiak also operates in the Green River basin of Wyoming and the Vermillion basin of Colorado.

Upside in the Eagle Ford

GeoResources also projects a broad range of potential returns.

The Houston-based independent expects to drill between 74 and 97 gross well across its 55,000 net acre leasehold in western North Dakota and eastern Montana in the Bakken.

The 25 percent rate of return Magnum Hunter cited refers to $8 million wells with an EUR rate of 300,000 barrels when oil prices are $90 per barrel.

That rate can fall to as low as 6.8 percent when oil prices are at $70 per barrel, but can increase to as high as 61.9 percent when oil prices are around $100 per barrel, average well costs fall to around $7 million and EUR rates increase to 450,000 barrels of oil.

By comparison, GeoResources reports a 25 percent return for its Eagle Ford wells, assuming $8 million well costs, $90 per barrel oil and an EUR rate of 325,000 barrels.

That range extends to greater peaks than the Bakken, though.

The rate can fall to as low as 8.4 percent when oil is at $70 per barrel and drilling costs average $9 million per well, but can increase to 127.1 percent when oil hits $100 per barrel, drilling costs fall to $8 million and average EUR rates increase to 500,000 barrels.

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